Contact: Ryan Hart 813-739-1354 rhart@seminole-electric.com

Friday, October 23, 2015

Seminole Electric Cooperative Challenges EPA “Clean Power Plan” in Federal Court TAMPA, FL – Today, Friday, October 23, 2015, Seminole Electric Cooperative, Inc., in partnership with the National Rural Electric Cooperative Association (NRECA), filed a “Petition to Review” the Environmental Protection Agency’s (EPA) Clean Power Plan (CPP). This petition asks the United States Court of Appeals for the District of Columbia Circuit to examine whether the CPP was legally enacted. Additionally, Seminole asked the court to delay compliance with the rule until the petition could be resolved. This delay is referred to as a “stay.” “The Clean Power Plan represents a massive overreach of EPA’s regulatory authority. Today’s filing is the next step in Seminole’s strategy to protect our Member cooperatives, and consumers at the end of the line, from the rate increases required to implement the Clean Power Plan,” said Lisa Johnson, Seminole’s CEO and General Manager. “Having exhausted all other measures, including testifying at EPA listening sessions, submitting detailed public comments about the rule, testifying in front of the Federal Energy Regulatory Commission, testifying in front of Congress, meeting with EPA Administrator Gina McCarthy, and meeting with the President’s Office of Management and Budget, Seminole is pursuing one of the few remaining options to protect the affordable, reliable electrical service that our Members enjoy today.” Based in Tampa, Florida, Seminole is one of the largest generation and transmission cooperatives in the country. Its mission is to provide reliable, competitively priced, wholesale electric power to its nine not-for-profit, consumer-owned distribution electric cooperatives. Seminole and its Members collectively serve 1.4 million individuals and businesses in 42 Florida counties, providing essential electric service in primarily rural and low income areas of Florida stretching from west of Tallahassee to south of Lake Okeechobee. Approximately one-third of Seminole’s residential customers have household incomes below the poverty level. “Unfortunately, despite the hundreds of millions of dollars of our Members’ resources that we have spent on state-of-the-art emissions control equipment, there is no commercially viable technology that we can install at our plants to meet the emissions rate requirements of the Clean Power Plan,” Johnson continued. “Seminole’s primary generating facility, the Seminole Generating Station, is currently financed through 2042. Should the EPA ultimately require us to close this plant, our Members will continue to make payments on it, while also needing to pay for new sources of electricity. Early estimates of the proposed rule have indicated that it may raise individual electric bills in Florida by more than 25%.”

Seminole operates two primary generating facilities, the coal-fired Seminole Generating Station (SGS) located in Palatka, Florida and the natural gas-fired Midulla Generating Station (MGS) located in Bowling Green, Florida. Seminole’s power plants cannot meet the emissions rates required by the CPP on a unit-by-unit basis. “While compliance options such as buying carbon emissions credits, or interstate carbon trading, may become available in the future, they are not available today,” said Johnson. “Without protection from the court system, Seminole will need to begin making planning decisions as if our plants are going to be shut down. As a result, Seminole is asking the court to review the rule to ensure that it is legally sound before we are forced to make the kinds of decisions that could close our plants and raise our Members’ electric rates.” The Federal Court System has shown a recent willingness to stand firm against EPA expansions of its own authority. Earlier this summer, the Supreme Court overturned EPA’s Mercury and Air Toxic Standards (MATS) rule after years of legal fighting. A federal court also recently delayed enforcement of the much maligned EPA “Waters of the United States” (WOTUS) rule, remarking that the stay “temporarily silences the whirlwind of confusion that springs from uncertainty about the requirements of the new rule and whether they will survive legal testing.” “While we recognize that our request for a stay of the Clean Power Plan may be an up-hill battle, Seminole is hopeful that the Court’s recent trend toward tempering the EPA’s regulatory onslaught will provide our Members with some relief,” said Johnson. “We’re just trying to keep the lights on in rural Florida.” Seminole’s nine member-owned distribution cooperatives are:

Central Florida Electric Cooperative, Chiefland, FL

Clay Electric Cooperative, Keystone Heights, FL

Glades Electric Cooperative, Moore Haven, FL

Peace River Electric Cooperative, Wauchula, FL

Sumter Electric Cooperative, Sumterville, FL

Suwannee Valley Electric Cooperative, Live Oak, FL

Talquin Electric Cooperative, Quincy, FL

Tri-County Electric Cooperative, Madison, FL

Withlacoochee River Electric Cooperative, Dade City, FL A copy of the declaration Seminole filed today is available here: (http://www.seminole-electric.com/pdf/compliance/33399966_Final_Seminole_Declaration-c.PDF) Individuals concerned about how the Clean Power Plan will affect them should visit www.action.coop to contact their elected officials.

### Seminole Electric is an equal opportunity provider and employer.

IN THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT

NATIONAL RURAL ELECTRIC COOPERATIVE ASSOCIATION, et al.

Petitioners,

v.

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY,

Respondent.

No. _____________

DECLARATION OF LISA D. JOHNSON OF SEMINOLE ELECTRIC

COOPERATIVE, INC. IN SUPPORT OF MOTION TO STAY

I, Lisa D. Johnson, declare:

1. I am the CEO & General Manager of Seminole Electric Cooperative,

Inc. (“Seminole”). In that capacity, I supervise more than 500 employees at three

principal locations in Florida. I am directly responsible to Seminole’s Board of

Trustees for overall Seminole operations.

2. I have worked for Seminole for two years, starting in July of 2013.

Before joining Seminole, I was senior Vice President and Chief Operating Officer

at Old Dominion Electric Cooperative in Glen Allen, Virginia. I hold a Bachelor of

Science Degree in Mechanical Engineering and Materials Science from Duke

University, and I have worked in the electric utility sector for over twenty years. I

serve as a Director on the Florida Reliability Coordinating Council, as the

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Secretary/Treasurer of the Florida Electric Power Coordinating Group, as a Trustee

on the Board of Averett University, as a Director and as a member of the Executive

Committee on the Board of the Florida Electric Cooperatives Association, as a

director on the Board of the Electric Power Research Institute, and as Second Vice-

President of the National G&T Managers Association. I was named one of

Virginia’s most “Influential Women” in 2012.

3. Seminole is one of the largest not-for-profit rural generation and

transmission (“G&T”) cooperatives in the country. Seminole has been in operation

since 1948 and became fully operational as a G&T cooperative in 1976. Seminole

and its nine Member-distribution cooperatives (collectively, “Seminole”) serve

approximately 1.4 million people and businesses in rural areas of Florida across 42

counties.

4. On August 3, 2015, the United States Environmental Protection

Agency (“EPA”) signed the final Carbon Pollution Emission Guidelines for

Existing Stationary Sources: Electric Utility Generating Units (“111(d) Rule” or

the “Rule”).

5. The 111(d) Rule requires a drastic reduction in carbon dioxide

(“CO2”) emissions from fossil fuel-fired generation, with a 32-percent reduction

from 2005 levels required by 2030. The 111(d) Rule achieves those reductions

through uniform CO2 emission performance rates EPA has imposed on two

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subcategories of existing power plants (coal- and natural gas-fired units), and

statewide rate- or mass-based emissions goals that are formulated from the

subcategory performance rates. States are required to formulate state plans for

compliance and submit those plans to EPA for approval.

6. Although states must plan for compliance, affected units like those

owned and operated by Seminole are responsible for compliance with the interim

and final goals established in the Rule. Seminole cannot meet the new performance

rates through any technological or operational changes at its existing units without

curtailing generation or shuttering the plants, shifting generation to lower-emitting

sources, and/or purchasing credits or allowances under a potential future trading

program.

7. The 111(d) Rule could force Seminole to commit to curtailing coal

and/or gas-fired generation or even shuttering all of its owned baseload and

intermediate load electricity generating facilities, including both coal-fired units at

Seminole Generating Station (“SGS”) and the natural gas-fired combined-cycle

unit at Midulla Generating Station (“MGS”) by 2022 to comply with the Rule.

Seminole will need to make planning and resource allocation decisions long before

any final state plans implementing the 111(d) Rule are submitted to EPA for

approval, before EPA’s proposed Federal Plan and model state trading rules are

finalized, and before this litigation is resolved. Because Seminole must make these

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business decisions almost immediately to prepare to comply with the 111(d) Rule,

Seminole and the communities it serves will incur imminent and irreparable

consequences if the Rule is not enjoined until this Court has had a full opportunity

for review.

Introduction to Seminole and its Generating Units

8. Like most electric cooperatives, Seminole serves rural areas that

would not be profitable or feasible for other utilities to serve, and that such utilities

historically declined to serve. As explained more fully in the Declaration of Kirk

Johnson, filed on behalf of the National Rural Electric Cooperative Association,

the principal purpose of rural electric cooperatives like Seminole is to provide

affordable electricity to underserved rural and largely lower-income populations.

To that end, Seminole provides essential electric service in primarily rural and low-

income areas of Florida stretching from west of Tallahassee to south of Lake

Okeechobee. Approximately one-third of Seminole’s residential customers have

household incomes below the poverty level. Seminole serves an average of less

than 10 customers per mile of electric line, whereas nationally, investor-owned

utilities average 34 customers per mile and publicly-owned utilities average 48

customers per mile. Some of Seminole’s Member cooperatives (“Members”) serve

as few as 4.6 customers per mile of electric line.

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9. The rural nature of Seminole’s business means that fewer customers

exist to share the costs of Seminole’s energy infrastructure. Because Seminole is a

not-for-profit cooperative, its costs are reflected directly in its rates for electricity.

10. Seminole’s primary generation resources include the coal-fired SGS

plant and the natural gas combined cycle (“NGCC”) unit at MGS. Most of

Seminole’s generation occurs at SGS in Putnam County in northern Florida. SGS

was constructed in the era of the “Powerplant and Industrial Fuel Use Act.” The

Act, which restricted new power plants from using oil or natural gas and

encouraged the use of coal, was enacted in 1978, and was not repealed until 1987.

SGS came online in 1984 and consists of two, 650-megawatt (“MW”) coal-fired

generating units. SGS has operated at an average capacity factor of 80 percent

throughout the last 18 years. In other words, SGS is very heavily utilized. In fact,

in 2014, SGS generated approximately 58 percent of the total energy Seminole

provided to its Members. Seminole engineering and consultant analyses estimate

that SGS has a remaining useful life of at least another 30 years.

11. Putnam County, Florida, in which SGS is situated, was identified by

USA Today as the poorest county in the State of Florida in 2015.1 Putnam County

1 The Poorest County in Each State, USA TODAY (Jan. 10, 2015), available at http://www.usatoday.com/story/money/personalfinance/2015/01/10/247-wall-st-poorest-county-each-state/21388095/ (last visited Aug. 26, 2015).

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has limited financial resources and is striving to improve its business and tax base.

Putnam County has been designated as a “Florida Rural Enterprise Zone,” which

provides for economic revitalization through tax incentives. The Governor also has

designated Putnam County as a “Rural Area of Opportunity” because it is

struggling to maintain, support, or enhance job activity, and to generate needed

revenues for education, infrastructure, transportation, and safety. Portions of

Putnam County also are within a U.S. Small Business Administration “Historically

Underutilized Business Zone,” which allows small businesses to gain preferential

access to federal procurement opportunities to promote economic development and

growth in distressed areas. These state and federal designations reflect the tenuous

economic status of the County and its residents.

12. SGS is one of the few major employers in Putnam County. SGS

directly employs more than 300 people, and it requires hundreds of additional

skilled contractors that work at the plant during maintenance outages and capital

project implementation. Between 400 and 650 contractors worked at SGS during

maintenance outages from 2012 to 2014. SGS is the largest taxpayer in Putnam

County, paying more than $5 million in property taxes in both 2013 and 2014. If

SGS is forced to close prematurely, or curtail its operations to comply with the

111(d) Rule, it will result in substantial layoffs. Putnam County will also suffer

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substantial economic consequences due to those layoffs and due to the reductions

in critical tax revenue.

13. Seminole also owns and operates MGS, an 810-MW (nominal)

generating facility that burns natural gas as its primary fuel, with ultra-low sulfur

fuel oil used as a back-up fuel. MGS began commercial operation in 2002 with a

500-MW NGCC unit, which consists of two natural gas-fired combustion turbines,

two heat-recovery steam generators, and one steam turbine. In 2006, Seminole

added 310-MW(nominal) of gas-fired peaking capacity, which can be operational

in as few as eight minutes to meet state operating reserve requirements. In 2014,

MGS’ NGCC unit provided approximately 17 percent of Seminole’s total energy

needs. Like SGS, MGS has a remaining useful life of at least another 30 years.

14. MGS is located on the county line between Hardee and Polk counties

in south central Florida, and employs 36 workers. Similar to Putnam County where

SGS is located, Hardee County has been designated as a “Florida Rural Enterprise

Zone” and as a “Rural Area of Opportunity.” Portions of Hardee County also are

within a U.S. Small Business Administration “Historically Underutilized Business

Zone.” Seminole paid more than $3 million annually in property taxes to Hardee

County in both 2013 and 2014.

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Summary of the 111(d) Rule

15. The 111(d) Rule establishes stringent CO2 emission guidelines that

states must follow to reduce CO2 emissions from existing fossil fuel-fired power

plants. Specifically, the Rule establishes: (a) unachievable CO2 emission

performance rates for two subcategories of existing power plants – steam

generating units (including coal-fired boilers) and stationary combustion turbines

(including natural gas-fired combined cycle units) – that EPA has nonetheless

determined represent the best system of emission reduction for existing fossil fuel-

fired power plants; (b) state-specific rate-based and mass-based CO2 emission

goals based on the unachievable subcategory rates and the state’s 2012 generation

mix; and (c) standards and requirements for the development, submittal,

implementation, and enforcement of state compliance plans that establish emission

standards or adopt other measures at least as stringent as the subcategory-specific

performance rates or state goals. While the Rule’s compliance period begins in

2022, and final standards must be achieved by 2030, regulated entities must begin

taking steps well in advance of those deadlines – many immediately – if they are to

comply by the specified deadlines.

16. As stated above, the Rule assigns a uniform performance rate for each

existing coal-fired and natural gas-fired electric generating unit (except excluded

combustion turbines) to reduce CO2 from existing power plants, measured in terms

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of pounds of CO2 emitted for every net megawatt hour, or lbs CO2/MWh-net. For

existing steam generating coal-fired units like SGS, the performance rate is 1,305

lbs CO2/MWh-net. For natural gas combined-cycle units like those at MGS, the

performance rate is 771 lbs CO2/MWh-net.

17. The Rule also sets forth statewide rate- and mass-based emission

goals for each state calculated from the weighted aggregate of emission

performance rates applicable to the state’s existing coal-, gas- and oil-fired power

plants. Florida’s final rate-based CO2 emission performance goal for 2030 is 919

lbs CO2/MWh-net, and its mass-based goal for existing affected units is

105,094,704 short tons of CO2.

18. Although the final state goals are not effective until 2030, the 111(d)

Rule also establishes a “glide path” with increasingly stringent interim emission

reduction requirements and average interim performance rates and goals for the

2022 to 2029 compliance period. Individual units must comply with both the

interim and final requirements.

19. States may directly impose source-specific emission standards or

requirements, or they may adopt other measures that achieve equivalent CO2

emission reductions from the same group of existing electric generating units.

Specifically, states may adopt an “emissions standards” plan that applies the source

subcategory-specific performance rates to affected units or applies other rate or

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mass-based standards to affected units that individually, or in the aggregate,

achieve EPA’s subcategory-specific performance rates, or state rate- or mass-based

goals upon implementation. Affected units could pursue compliance measures such

as heat rate improvements, investing in or transitioning generation to existing

natural gas combined cycle, renewable, or nuclear electricity generation, or use of

an emissions credit/allowance trading system. States also may adopt a “state

measures” plan that includes, at least in part, measures imposed on entities other

than existing electric generating units covered under the Rule, as well as a

backstop of federally enforceable standards for individual power plants that are

triggered if the state measures do not achieve the required emission reductions.

States also may band together to adopt a multi-state plan applying either an

“emissions standards” or “state measures” approach.

20. Regardless of which compliance approach states choose, emission

reductions from affected electric generating units like those at SGS and MGS –

individually, in the aggregate, or in combination with other measures taken by the

state – must achieve the equivalent of the EPA-specified CO2 emission

performance rates by 2030, expressed via the state-specific rate- or mass-based

goals. States must abide by the goals set by EPA; they are not free to adopt less

stringent goals.

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21. The apparent flexibility of the EPA process for crafting a state

implementation plan creates the kind of uncertainty that is impracticable to plan

for. Seminole is forced to make imminent planning decisions based on the most

stringent, inflexible outcome possible, causing irreparable harm if other more

flexible options become available at a later date under yet-to-be-determined

rulemakings. States must submit at least an initial state plan to EPA by September

6, 2016. The 111(d) Rule allows states to seek an extension to September 6, 2018,

to submit a final plan. EPA has pledged to review and approve state plans within a

year of their submission. The State of Florida thus has until September 6, 2018, to

submit a final plan so long as it submits an initial plan for compliance by

September 6, 2016, and seeks an extension from EPA. It will not be clear what

compliance methods will be ultimately adopted by the State – including whether a

trading program will be established, the terms of any such program, or whether that

program will be acceptable to EPA – until the plan is finalized and approved

sometime in late 2018 or 2019. The State also has the discretion to choose not to

adopt a trading program in favor of other methods of compliance. In short, there is

likely to be no certainty about the shape of Florida’s plan, whether trading will be

available under it and, if so, on what terms trading will be available, for at least

another four years.

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The Rule’s Effect on Seminole

22. Neither of Seminole’s primary generating resources can meet the final

111(d) Rule’s performance rate for existing steam generating coal-fired and natural

gas combined cycle plants, nor can they meet the interim rate. As noted above, the

performance rates are among the few key metrics finalized by EPA as of the

August 3 signature. Accordingly, when dealing with forced current realities (i.e.,

required generation planning) as opposed to future possibilities under whatever

type of plan Florida ultimately adopts, SGS would be permitted to emit no more

than 1,305 lbs CO2/MWh-net annually, and the MGS NGCC unit would be

permitted to emit no more than 771 lbs CO2/MWh-net annually, by 2030. The

interim rates, which must be met by 2022, would permit SGS to emit no more than

1,534 lbs CO2/MWh-net annually, and the MGS NGCC unit would be permitted to

emit no more than 832 lbs CO2/MWh-net annually. Over the past 5 years, SGS has

emitted CO2 at an average annual rate of 2,006 lbs CO2/MWh-net, more than 700

lbs more per MWh-net than permitted by the 111(d) Rule when fully implemented.

MGS has emitted CO2 at an average annual rate of 905 lbs CO2/MWh-net, more

than 130 lbs more per MWh-net than permitted by the 111(d) Rule when fully

implemented.

23. Because SGS and MGS cannot meet the uniform performance rates,

the 111(d) Rule’s strict requirements are placing all of Seminole’s owned base-

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load and intermediate generating facilities at SGS and MGS in jeopardy of being

curtailed, shuttered, and/or replaced. In 2014, these assets provided 76 percent of

Seminole’s total energy needs. They are outfitted with state-of-the-art emission

control systems and, having reached approximately half of their expected useful

lives, are relatively new facilities, yet they cannot even come close to meeting the

EPA’s stringent 111(d) emission limits. Seminole has invested more than $530

million on state-of-the-art environmental control equipment at SGS since the plant

came online in 1984 and more than $262.4 million has been invested since 2006

alone. Should the plant be shuttered and/or replaced, these investments will be lost.

24. There is no viable, adequately demonstrated environmental control

system that Seminole can install at SGS or MGS to meet the new performance

rates. The only means for SGS and the MGS NGCC unit to achieve the Rule’s

emission rates are: (i) curtailment of operations and replacement of the lost

generation with lower-emitting generation (e.g., natural gas-fired units and

renewable generation) obtained elsewhere; (ii) closure of the facilities entirely and

replacement of the units with new natural gas-fired units and renewable generation;

or (iii) purchase of emission reduction credits or allowances through a trading

system that might be established pursuant to the 111(d) Rule.

25. The first two options explained in the previous paragraph (curtailment

and replacement, or closure and replacement) will require the premature closure

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and/or curtailment of SGS, and possibly the NGCC unit at MGS, at extraordinary

cost to Seminole and its Members. More specifically, Seminole does not currently

have sufficient owned or contracted lower-emitting generation capacity to replace

all or part of the generation provided by SGS and the NGCC unit at MGS. Even if

the NGCC unit at MGS could meet EPA’s emission limits, it does not have

sufficient capacity to replace lost generation from coal-fired SGS. The MGS

NGCC unit has operated at an average capacity factor of 62 percent since 2012;

this capacity factor leaves little room for Seminole to ramp up output at MGS to

offset curtailed generation from the SGS coal-fired facility, as contemplated by

EPA with their imposition of a 75 percent capacity factor requirement for gas-fired

facilities. Seminole could also construct additional renewable generation, but it is

not feasible to replace the baseload and intermediate generation provided by SGS

and MGS wholly with intermittent renewable generation resources given their

unpredictability and low capacity factor.

26. To comply with the final 111(d) Rule, then, Seminole must choose to

construct new generation facilities or to contract for purchased power supply from

third parties. In addition, Seminole must contract for natural gas to be used to fuel

its own generation and potentially must contract for natural gas to be used at its

purchased power resource facilities. Under any option, Seminole must make these

irrevocable decisions soon as explained in the next paragraph. In addition,

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Seminole must decide by early 2016 if it will build replacement generation

resources or enter into one or more purchased power agreements. Considering the

uncertainty created by the 111(d) Rule throughout the electric generation industry,

it is questionable whether Seminole will be able to obtain any purchased power

resources. If Seminole must construct its own gas-fired power plants by 2022, it

must decide in 2016 whether to replace all generation at SGS and MGS or some

portion of these resources, which is prior to any final regulatory direction provided

by EPA or the State of Florida. These investments must be funded by consumers,

resulting in extraordinary rate increases. Seminole’s Members and their end-use

consumers cannot withstand this added financial burden. If the Court invalidates

the Clean Power Plan, these new investments will not be needed but consumers

will have already suffered from the unnecessary and irreparable rate-increases.

27. To replace SGS alone, Seminole would have to choose and evaluate

potential sites and apply for the requisite environmental and local permits, at a cost

of approximately $2 million. As explained above, this irreparable effort and

expense would need to begin by mid-2016. By the middle of 2018, Seminole also

would have to contract to purchase generation equipment for the new plant at a

cost of approximately $375 million. If the decision is made to replace the MGS

NGCC unit by constructing an equivalently-sized new gas-fired combined cycle

facility, Seminole would be required to spend an additional $150 million in the

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same time frame.2 Alternatively, if Seminole chooses to contract for the purchase

of power and/or natural gas generating capacity, Seminole would have to negotiate

and enter into the necessary contract(s) by mid-2018.

28. The total cost to Seminole of replacing 1,800 MW of capacity

generated by SGS and the MGS NGCC unit is expected to be at least $1.8 billion.

Replacing SGS’s output would cost Seminole approximately $1.3 billion, and the

cost of replacing the MGS NGCC unit’s output would be approximately $500

million. These figures could be even higher if the gas-fired equipment and

construction markets surge in response to the 111(d) Rule. Seminole would have to

obtain financing, starting with powertrain payments of $525 million ($375 million

to replace SGS and $150 million to replace the MGS NGCC unit) that would be

made in mid-2018. Because Seminole will be carrying approximately $836 million

in outstanding debt (as of December 2021) associated with the prematurely-retired

SGS and MGS units when it obtains that additional financing, its credit rating also

may be negatively affected. Credit rating downgrades extend across all aspects of a

utility, negatively affecting contracts, financing, and rates. Seminole would have to

accelerate the depreciation schedule for SGS from a 30-year remaining life to a

significantly shorter useful life. Seminole’s rates would be forced to increase to

2 These costs represent only the initial power train equipment purchases that must be made by mid-2018, not the cost to replace SGS and MGS entirely.

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cover the costs of new gas and/or renewable generation while continuing to pay for

the sunk costs and outstanding debt associated with SGS and MGS.

29. Seminole also must decide before the end of 2016 whether to forgo

planned investments in SGS, which are intended to maintain its efficient and

environmentally-responsible operations. The uncertainty created by the 111(d)

Rule thus creates another “roll of the dice” decision that must be made by

Seminole. Seminole must choose now whether to spend additional money on

improvements and risk losing the investments if the facility is prematurely retired,

or choose not to spend the money and forgo the environmental benefits and

efficiency gains that could be achieved.

30. Regardless of whether Seminole constructs new generation or enters

into purchased power contracts with others to achieve compliance, Seminole would

need to contract to increase its gas transportation capacity (via pipeline) before the

end of 2016. The cost of constructing a gas pipeline to serve new gas-fired units is

estimated to cost more than $80 million, $8 million of which may need to be paid

before the end of 2016 to initiate the construction process. The enormous cost of

the required investments – completely unnecessary and imprudently made if the

Rule is eventually overturned – would be unrecoverable from the United States

even if the 111(d) Rule is vacated. It is important to note that all of the additional

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costs described above are on top of and in addition to the costs required to meet

expected future demand for our Members.

31. The third option for compliance described above – purchase of

emission reduction credits or allowances under a 111(d) Rule-compliant trading

program – will not even be available to Seminole unless Florida adopts such a

system. Seminole will not know with any certainty whether such trading will be

available until late 2018 or in 2019, because the state plan requires development

and EPA approval, both of which are time consuming. As noted above, Seminole

will need to make decisions and commit to significant expenditures starting in

2016 regarding the generation resources that will be online in 2022 and beyond. It

does not have the luxury of waiting to see if Florida adopts a trading program or if

that program will provide sufficient credits or allowances, at economic prices, to

allow the continued operation of SGS and the NGCC unit at MGS.

32. Seminole is a not-for-profit cooperative that cannot absorb the

enormous costs of constructing a lower-emitting generating facility or contracting

for lower-emitting generating capacity without passing along those costs to its

Members. Premature closure of SGS, and potentially the NGCC unit at MGS, and

the inability of Seminole to replace that generating capacity at a cost that would be

affordable to Seminole’s Members will have significant detrimental impacts on

Seminole and its Members’ consumers: (1) SGS’s approximately 300 employees

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will lose their jobs (and hundreds of contract-work opportunities will also be lost);

(2) Seminole will no longer operate in its current form, having lost its principal

generating unit(s); (3) Seminole will lose an annual multi-million dollar revenue

stream from a contract with Continental Building Products (“Continental”), under

which Continental purchases synthetic gypsum (a byproduct of combustion,

produced by SGS’s environmental control systems) and recycles that product to

make wallboard; (4) Seminole’s rates will increase and may no longer be

competitive with other utilities in the state, driving much needed economic

development out of Florida’s rural areas; and (5) the entire objective of the

federally-crafted rural cooperative structure will be undermined.3

33. Unless the 111(d) Rule is stayed pending judicial review, Seminole

must take the immediate and irreversible steps described above causing Seminole

and its Members’ consumers to suffer immediate and irreparable harm. If the

111(d) Rule is later invalidated, without a stay, Seminole will have already

committed to a combination of the following irreparable actions: premature

closings and/or significant curtailment of its operating power generation facilities,

significant expenditures on natural gas and/or renewable generation facilities, and

3 See Kirk Johnson Decl., ¶¶ 6-9, 11 (discussing the purpose and formation of rural electric cooperatives).

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new gas pipeline construction and/or purchase contracts.

October 12th

ORAL ARGUMENT SCHEDULED FOR JUNE 2, 2016

No. 15-1363 (and consolidated cases) ______________________________________

IN THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT

_______________________________________

STATE OF WEST VIRGINIA, et al., Petitioners,

V.

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, et al.,

Respondents. ______________________________________

On Petition for Review of Final Agency Action of the United States Environmental Protection Agency

80 Fed. Reg. 64,662 (Oct. 23, 2015) ______________________________________

OPENING BRIEF OF PETITIONERS ON PROCEDURAL AND RECORD-BASED ISSUES

______________________________________

Thomas A. Lorenzen Sherrie A. Armstrong CROWELL & MORING LLP 1001 Pennsylvania Ave., N.W. Washington, D.C. 20004 Tel: (202) 624-2500 tlorenzen@crowell.com sarmstrong@crowell.com

Counsel for Petitioners National Rural Electric Cooperative Association, et al.

DATED: February 19, 2016

Patrick Morrisey ATTORNEY GENERAL OF WEST VIRGINIA Elbert Lin Solicitor General Counsel of Record J. Zak Ritchie Assistant Attorney General State Capitol Building 1, Room 26-E Charleston, WV 25305 Tel: (304) 558-2021 Fax: (304) 558-0140 elbert.lin@wvago.gov Counsel for Petitioner State of West Virginia

Additional counsel listed on following pages

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Ken Paxton ATTORNEY GENERAL OF TEXAS Charles E. Roy First Assistant Attorney General Scott A. Keller Solicitor General Counsel of Record P.O. Box 12548 Austin, TX 78711-2548 Tel: (512) 936-1700 scott.keller@texasattorneygeneral.gov Counsel for Petitioner State of Texas

Luther Strange ATTORNEY GENERAL OF ALABAMA Andrew Brasher Solicitor General Counsel of Record 501 Washington Avenue Montgomery, AL 36130 Tel: (334) 590-1029 abrasher@ago.state.al.us Counsel for Petitioner State of Alabama

Mark Brnovich ATTORNEY GENERAL OF ARIZONA John R. Lopez IV Counsel of Record Dominic E. Draye Keith Miller Assistant Attorneys General Maureen Scott Janet Wagner Janice Alward Arizona Corp. Commission, Staff Attorneys 1275 West Washington Phoenix, AZ 85007 Tel: (602) 542-5025 john.lopez@azag.gov dominic.draye@azag.gov keith.miller@azag.gov Counsel for Petitioner Arizona Corporation Commission

Leslie Rutledge ATTORNEY GENERAL OF ARKANSAS Lee Rudofsky Solicitor General Jamie L. Ewing Assistant Attorney General Counsel of Record 323 Center Street, Suite 400 Little Rock, AR 72201 Tel: (501) 682-5310 jamie.ewing@arkansasag.gov Counsel for Petitioner State of Arkansas

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Cynthia H. Coffman ATTORNEY GENERAL OF COLORADO Frederick Yarger Solicitor General Counsel of Record 1300 Broadway, 10th Floor Denver, CO 80203 Tel: (720) 508-6168 fred.yarger@state.co.us Counsel for Petitioner State of Colorado

Pamela Jo Bondi ATTORNEY GENERAL OF FLORIDA Allen Winsor Solicitor General of Florida Counsel of Record Office of the Attorney General PL-01, The Capitol Tallahassee, FL 32399-1050 Tel: (850) 414-3681 Fax: (850) 410-2672 allen.winsor@myfloridalegal.com Counsel for Petitioner State of Florida

Samuel S. Olens ATTORNEY GENERAL OF GEORGIA Britt C. Grant Solicitor General Counsel of Record 40 Capitol Square S.W. Atlanta, GA 30334 Tel: (404) 656-3300 Fax: (404) 463-9453 bgrant@law.ga.gov Counsel for Petitioner State of Georgia

Gregory F. Zoeller ATTORNEY GENERAL OF INDIANA Timothy Junk Deputy Attorney General Counsel of Record Indiana Government Ctr. South Fifth Floor 302 West Washington Street Indianapolis, IN 46205 Tel: (317) 232-6247 tim.junk@atg.in.gov Counsel for Petitioner State of Indiana

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Derek Schmidt ATTORNEY GENERAL OF KANSAS Jeffrey A. Chanay Chief Deputy Attorney General Counsel of Record Bryan C. Clark Assistant Solicitor General 120 S.W. 10th Avenue, 3rd Floor Topeka, KS 66612 Tel: (785) 368-8435 Fax: (785) 291-3767 jeff.chanay@ag.ks.gov Counsel for Petitioner State of Kansas

Andy Beshear ATTORNEY GENERAL OF KENTUCKY Gregory T. Dutton Assistant Attorney General Counsel of Record 700 Capital Avenue Suite 118 Frankfort, KY 40601 Tel: (502) 696-5453 gregory.dutton@ky.gov Counsel for Petitioner Commonwealth of Kentucky

Jeff Landry ATTORNEY GENERAL OF LOUISIANA Steven B. “Beaux” Jones Counsel of Record Duncan S. Kemp, IV Assistant Attorneys General Environmental Section – Civil Division 1885 N. Third Street Baton Rouge, LA 70804 Tel: (225) 326-6085 Fax: (225) 326-6099 jonesst@ag.state.la.us Counsel for Petitioner State of Louisiana

Herman Robinson Executive Counsel Donald Trahan Counsel of Record Elliott Vega LOUISIANA DEPARTMENT OF

ENVIRONMENTAL QUALITY Legal Division P.O. Box 4302 Baton Rouge, LA 70821-4302 Tel: (225) 219-3985 Fax: (225) 219-4068 donald.trahan@la.gov Counsel for Petitioner State of Louisiana Department of Environmental Quality

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Monica Derbes Gibson Lesley Foxhall Pietras LISKOW & LEWIS, P.L.C. 701 Poydras Street, Suite 5000 New Orleans, LA 70139 Tel: (504) 556-4010 Fax: (504) 556-4108 mdgibson@liskow.com lfpietras@liskow.com Counsel for Petitioner Louisiana Public Service Commission

Bill Schuette ATTORNEY GENERAL FOR THE PEOPLE OF MICHIGAN Aaron D. Lindstrom Michigan Solicitor General Counsel of Record P.O. Box 30212 Lansing, MI 48909 Tel: (515) 373-1124 Fax: (517) 373-3042 lindstroma@michigan.gov Counsel for Petitioner People of the State of Michigan

Jim Hood ATTORNEY GENERAL OF THE STATE OF MISSISSIPPI Harold E. Pizzetta Assistant Attorney General Civil Litigation Division Office of the Attorney General Post Office Box 220 Jackson, MS 39205 Tel: (601) 359-3816 Fax: (601) 359-2003 hpizz@ago.state.ms.us Counsel for Petitioner State of Mississippi

Donna J. Hodges Senior Counsel MISSISSIPPI DEPARTMENT OF

ENVIRONMENTAL QUALITY P.O. Box 2261 Jackson, MS 39225-2261 Tel: (601) 961-5369 Fax: (601) 961-5349 donna_hodges@deq.state.ms.us Counsel for Petitioner Mississippi Department of Environmental Quality

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Todd E. Palmer Valerie L. Green MICHAEL, BEST & FRIEDRICH LLP 601 Pennsylvania Ave., N.W., Suite 700 Washington, D.C. 20004-2601 Tel: (202) 747-9560 Fax: (202) 347-1819 tepalmer@michaelbest.com vlgreen@michaelbest.com Counsel for Petitioner Mississippi Public Service Commission

Chris Koster ATTORNEY GENERAL OF MISSOURI James R. Layton Solicitor General Counsel of Record P.O. Box 899 207 W. High Street Jefferson City, MO 65102 Tel: (573) 751-1800 Fax: (573) 751-0774 james.layton@ago.mo.gov Counsel for Petitioner State of Missouri

Timothy C. Fox ATTORNEY GENERAL OF MONTANA Alan Joscelyn Chief Deputy Attorney General Dale Schowengerdt Solicitor General Counsel of Record 215 North Sanders Helena, MT 59620-1401 Tel: (406) 444-7008 dales@mt.gov Counsel for Petitioner State of Montana

Doug Peterson ATTORNEY GENERAL OF NEBRASKA Dave Bydlaek Chief Deputy Attorney General Justin D. Lavene Assistant Attorney General Counsel of Record 2115 State Capitol Lincoln, NE 68509 Tel: (402) 471-2834 justin.lavene@nebraska.gov Counsel for Petitioner State of Nebraska

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John J. Hoffman ACTING ATTORNEY GENERAL OF NEW JERSEY David C. Apy Assistant Attorney General Robert J. Kinney Deputy Attorney General Counsel of Record Division of Law R.J. Hughes Justice Complex P.O. Box 093 25 Market Street Trenton, NJ 08625-0093 Tel: (609) 292-6945 Fax: (609) 341-5030 robert.kinney@dol.lps.state.nj.us Counsel for Petitioner State of New Jersey

Wayne Stenehjem ATTORNEY GENERAL OF NORTH DAKOTA Margaret Olson Assistant Attorney General North Dakota Attorney General’s Office 600 E. Boulevard Avenue #125 Bismarck, ND 58505 Tel: (701) 328-3640 maiolson@nd.gov Paul M. Seby Special Assistant Attorney General State of North Dakota GREENBERG TRAURIG, LLP 1200 17th Street, Suite 2400 Denver, CO 80202 Tel: (303) 572-6500 Fax: (303) 572-6540 sebyp@gtlaw.com Counsel for Petitioner State of North Dakota

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Michael DeWine ATTORNEY GENERAL OF OHIO Eric E. Murphy State Solicitor Counsel of Record 30 E. Broad Street, 17th Floor Columbus, OH 43215 Tel: (614) 466-8980 eric.murphy@ohioattorneygeneral.gov Counsel for Petitioner State of Ohio

E. Scott Pruitt ATTORNEY GENERAL OF OKLAHOMA Patrick R. Wyrick Solicitor General of Oklahoma 313 N.E. 21st Street Oklahoma City, OK 73105 Tel: (405) 521-4396 Fax: (405) 522-0669 fc.docket@oag.state.ok.us scott.pruitt@oag.ok.gov David B. Rivkin, Jr. Counsel of Record Mark W. DeLaquil Andrew M. Grossman BAKER & HOSTETLER LLP Washington Square, Suite 1100 1050 Connecticut Ave., N.W. Washington, D.C. 20036 Tel: (202) 861-1731 Fax: (202) 861-1783 drivkin@bakerlaw.com Counsel for Petitioners State of Oklahoma and Oklahoma Department of Environmental Quality

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Alan Wilson ATTORNEY GENERAL OF SOUTH CAROLINA Robert D. Cook Solicitor General James Emory Smith, Jr. Deputy Solicitor General Counsel of Record P.O. Box 11549 Columbia, SC 29211 Tel: (803) 734-3680 Fax: (803) 734-3677 esmith@scag.gov Counsel for Petitioner State of South Carolina

Marty J. Jackley ATTORNEY GENERAL OF SOUTH DAKOTA Steven R. Blair Assistant Attorney General Counsel of Record 1302 E. Highway 14, Suite 1 Pierre, SD 57501 Tel: (605) 773-3215 steven.blair@state.sd.us Counsel for Petitioner State of South Dakota

Sean Reyes ATTORNEY GENERAL OF UTAH Tyler R. Green Solicitor General Counsel of Record Parker Douglas Federal Solicitor Utah State Capitol Complex 350 North State Street, Suite 230 Salt Lake City, UT 84114-2320 pdouglas@utah.gov Counsel for Petitioner State of Utah

Brad Schimel ATTORNEY GENERAL OF WISCONSIN Misha Tseytlin Solicitor General Counsel of Record Andrew Cook Deputy Attorney General Delanie M. Breuer Assistant Deputy Attorney General Wisconsin Department of Justice 17 West Main Street Madison, WI 53707 Tel: (608) 267-9323 tseytlinm@doj.state.wi.us Counsel for Petitioner State of Wisconsin

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Peter K. Michael ATTORNEY GENERAL OF WYOMING James Kaste Deputy Attorney General Counsel of Record Michael J. McGrady Erik Petersen Senior Assistant Attorneys General Elizabeth Morrisseau Assistant Attorney General 2320 Capitol Avenue Cheyenne, WY 82002 Tel: (307) 777-6946 Fax: (307) 777-3542 james.kaste@wyo.gov Counsel for Petitioner State of Wyoming

Sam M. Hayes General Counsel Counsel of Record Craig Bromby Deputy General Counsel Andrew Norton Deputy General Counsel NORTH CAROLINA DEPARTMENT OF

ENVIRONMENTAL QUALITY 1601 Mail Service Center Raleigh, NC 27699-1601 Tel: (919) 707-8616 sam.hayes@ncdenr.gov Counsel for Petitioner North Carolina Department of Environmental Quality

Dennis Lane STINSON LEONARD STREET LLP 1775 Pennsylvania Ave., N.W., Suite 800 Washington, D.C. 20006 Tel: (202) 785-9100 Fax: (202) 785-9163 dennis.lane@stinson.com Parthenia B. Evans STINSON LEONARD STREET LLP 1201 Walnut Street, Suite 2900 Kansas City, MO 64106 Tel: (816) 842-8600 Fax: (816) 691-3495 parthy.evans@stinson.com Counsel for Petitioner Kansas City Board of Public Utilities – Unified Government of Wyandotte County/Kansas City, Kansas

F. William Brownell Allison D. Wood Henry V. Nickel Tauna M. Szymanski HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 bbrownell@hunton.com awood@hunton.com hnickel@hunton.com tszymanski@hunton.com Counsel for Petitioners Utility Air Regulatory Group and American Public Power Association

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Stacey Turner SOUTHERN COMPANY SERVICES, INC. 600 18th Street North BIN 14N-8195 Birmingham, AL 35203 Tel: (205) 257-2823 staturne@southernco.com Counsel for Petitioners Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company Margaret Claiborne Campbell Angela J. Levin TROUTMAN SANDERS LLP 600 Peachtree Street, NE, Suite 5200 Atlanta, GA 30308-2216 Tel: (404) 885-3000 margaret.campbell@troutmansanders.com angela.levin@troutmansanders.com Counsel for Petitioner Georgia Power Company

C. Grady Moore, III Steven G. McKinney BALCH & BINGHAM LLP 1901 Sixth Avenue North, Suite 1500 Birmingham, AL 35303-4642 Tel: (205) 251-8100 Fax: (205) 488-5704 gmoore@balch.com smckinney@balch.com Counsel for Petitioner Alabama Power Company Terese T. Wyly Ben H. Stone BALCH & BINGHAM LLP 1310 Twenty Fifth Avenue Gulfport, MS 39501-1931 Tel: (228) 214-0413 twyly@balch.com bstone@balch.com Counsel for Petitioner Mississippi Power Company

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Jeffrey A. Stone BEGGS & LANE, RLLP 501 Commendencia Street Pensacola, FL 32502 Tel: (850) 432-2451 JAS@beggslane.com James S. Alves 2110 Trescott Drive Tallahassee, FL 32308 Tel: (850) 566-7607 jim.s.alves@outlook.com Counsel for Petitioner Gulf Power Company

Christina F. Gomez Lawrence E. Volmert Garrison W. Kaufman Jill H. Van Noord HOLLAND & HART LLP 555 Seventeenth Street, Suite 3200 Denver, CO 80202 Tel: (303) 295-8000 Fax: (303) 295-8261 cgomez@hollandhart.com lvolmert@hollandhart.com gwkaufman@hollandhart.com jhvannoord@hollandhart.com Patrick R. Day HOLLAND & HART LLP 2515 Warren Avenue, Suite 450 Cheyenne, WY 82001 Tel: (307) 778-4200 Fax: (307) 778-8175 pday@hollandhart.com Emily C. Schilling HOLLAND & HART LLP 222 South Main Street, Suite 2200 Salt Lake City, UT 84101 Tel: (801) 799-5800 Fax: (801) 799-5700 ecschilling@hollandhart.com Counsel for Petitioner Basin Electric Power Cooperative

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James S. Alves 2110 Trescott Drive Tallahassee, FL 32308 Tel: (850) 566-7607 jim.s.alves@outlook.com Counsel for Petitioner CO2 Task Force of the Florida Electric Power Coordinating Group, Inc.

John J. McMackin WILLIAMS & JENSEN 701 8th Street, N.W., Suite 500 Washington, D.C. 20001 Tel: (202) 659-8201 jjmcmackin@wms-jen.com Counsel for Petitioner Energy-Intensive Manufacturers Working Group on Greenhouse Gas Regulation

William M. Bumpers Megan H. Berge BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004 Tel: (202) 639-7700 william.bumpers@bakerbotts.com megan.berge@bakerbotts.com Kelly McQueen ENTERGY SERVICES, INC. 425 W. Capitol Avenue, 27th Floor Little Rock, AR 72201 Tel: (501) 377-5760 kmcque1@entergy.com Counsel for Petitioner Entergy Corporation

Paul J. Zidlicky SIDLEY AUSTIN, LLP 1501 K Street, N.W. Washington, D.C. 20005 Tel: (202) 736-8000 pzidlicky@sidley.com Counsel for Petitioners GenOn Mid-Atlantic, LLC; Indian River Power LLC; Louisiana Generating LLC; Midwest Generation, LLC; NRG Chalk Point LLC; NRG Power Midwest LP; NRG Rema LLC; NRG Texas Power LLC; NRG Wholesale Generation LP; and Vienna Power LLC

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David M. Flannery Kathy G. Beckett Edward L. Kropp STEPTOE & JOHNSON, PLLC 505 Virginia Street East Charleston, WV 25326 Tel: (304) 353-8000 dave.flannery@steptoe-johnson.com kathy.beckett@steptoe-johnson.com skipp.kropp@steptoe-johnson.com Stephen L. Miller STEPTOE & JOHNSON, PLLC 700 N. Hurstbourne Parkway, Suite 115 Louisville, KY 40222 Tel: (502) 423-2000 steve.miller@steptoe-johnson.com Counsel for Petitioner Indiana Utility Group

F. William Brownell Eric J. Murdock HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 bbrownell@hunton.com emurdock@hunton.com Nash E. Long III HUNTON & WILLIAMS LLP Bank of America Plaza, Suite 3500 101 South Tryon Street Charlotte, NC 28280 Tel: (704) 378-4700 nlong@hunton.com Counsel for Petitioner LG&E and KU Energy LLC

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P. Stephen Gidiere III Thomas L. Casey III Julia B. Barber BALCH & BINGHAM LLP 1901 6th Ave. N., Suite 1500 Birmingham, AL 35203 Tel: (205) 251-8100 sgidiere@balch.com Stephanie Z. Moore Vice President and General Counsel Luminant Generation Company LLC 1601 Bryan Street, 22nd Floor Dallas, TX 75201 Daniel J. Kelly Vice President and Associate General Counsel Energy Future Holdings Corp. 1601 Bryan Street, 43rd Floor Dallas, TX 75201 Counsel for Petitioners Luminant Generation Company LLC; Oak Grove Management Company LLC; Big Brown Power Company LLC; Sandow Power Company LLC; Big Brown Lignite Company LLC; Luminant Mining Company LLC; and Luminant Big Brown Mining Company LLC

Ronald J. Tenpas MORGAN, LEWIS & BOCKIUS 1111 Pennsylvania Avenue, N.W. Washington, D.C. 20004 Tel: (202) 739-3000 rtenpas@morganlewis.com Counsel for Petitioner Minnesota Power (an operating division of ALLETE, Inc.)

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Allison D. Wood Tauna M. Szymanski Andrew D. Knudsen HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 awood@hunton.com tszymanski@hunton.com aknudsen@hunton.com Counsel for Petitioner Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc.

Joshua R. More Jane E. Montgomery Amy Antoniolli Raghav Murali SCHIFF HARDIN LLP 233 South Wacker Drive Suite 6600 Chicago, IL 60606 Tel: (312) 258-5500 jmore@schiffhardin.com jmontgomery@schiffhardin.com aantoniolli@schiffhardin.com rmurali@schiffhardin.com Counsel for Petitioner Prairie State Generating Company, LLC

Of Counsel Rae Cronmiller Environmental Counsel NATIONAL ASSOCIATION OF RURAL

ELECTRIC COOPERATIVES 4301 Wilson Blvd. Arlington, VA 22203 Tel: (703) 907-5500 rae.cronmiller@nreca.coop

Eric L. Hiser JORDEN BISCHOFF & HISER, PLC 7272 E. Indian School Road, Suite 360 Scottsdale, AZ 85251 Tel: (480) 505-3927 ehiser@jordenbischoff.com Counsel for Petitioner Arizona Electric Power Cooperative, Inc.

Brian A. Prestwood Senior Corporate and Compliance Counsel ASSOCIATED ELECTRIC COOPERATIVE, INC. 2814 S. Golden, P.O. Box 754 Springfield, MO 65801 Tel: (417) 885-9273 bprestwood@aeci.org Counsel for Petitioner Associated Electric Cooperative, Inc.

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Christopher L. Bell GREENBERG TRAURIG LLP 1000 Louisiana Street, Suite 1700 Houston, TX 77002 Tel: (713) 374-3556 bellc@gtlaw.com Counsel for Petitioner Golden Spread Electrical Cooperative, Inc.

David Crabtree Vice President, General Counsel DESERET GENERATION & TRANSMISSION

CO-OPERATIVE 10714 South Jordan Gateway South Jordan, UT 84095 Tel: (801) 619-9500 Crabtree@deseretpower.com Counsel for Petitioner Deseret Generation & Transmission Co-operative

John M. Holloway III, DC Bar # 494459 SUTHERLAND ASBILL & BRENNAN LLP 700 Sixth Street, N.W., Suite 700 Washington, D.C. 20001 Tel: (202) 383-0100 Fax: (202) 383-3593 jay.holloway@sutherland.com Counsel for Petitioners East Kentucky Power Cooperative, Inc.; Hoosier Energy Rural Electric Cooperative, Inc.; Minnkota Power Cooperative, Inc.; and South Mississippi Electric Power Association

Patrick Burchette HOLLAND & KNIGHT LLP 800 17th Street, N.W., Suite 1100 Washington, D.C. 20006 Tel: (202) 469-5102 Patrick.Burchette@hklaw.com Counsel for Petitioners East Texas Electric Cooperative, Inc.; Northeast Texas Electric Cooperative, Inc.; Sam Rayburn G&T Electric Cooperative, Inc.; and Tex-La Electric Cooperative of Texas, Inc.

Mark Walters D.C. Cir. Bar No. 54161 Michael J. Nasi D.C. Cir. Bar No. 53850 JACKSON WALKER L.L.P. 100 Congress Avenue, Suite 1100 Austin, TX 78701 Tel: (512) 236-2000 mwalters@jw.com mnasi@jw.com Counsel for Petitioners San Miguel Electric Cooperative, Inc. and South Texas Electric Cooperative, Inc.

Randolph G. Holt Jeremy L. Fetty PARR RICHEY OBREMSKEY FRANDSEN &

PATTERSON LLP Wabash Valley Power Association, Inc. 722 N. High School Road P.O. Box 24700 Indianapolis, IN 46224 Tel: (317) 481-2815 R_holt@wvpa.com jfetty@parrlaw.com Counsel for Petitioner Wabash Valley Power Association, Inc.

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Megan H. Berge BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004 Tel: (202) 639-7700 megan.berge@bakerbotts.com Counsel for Petitioner Western Farmers Electric Cooperative

Steven C. Kohl Gaetan Gerville-Reache WARNER NORCROSS & JUDD LLP 2000 Town Center, Suite 2700 Southfield, MI 48075-1318 Tel: (248) 784-5000 skohl@wnj.com Counsel for Petitioner Wolverine Power Supply Cooperative, Inc.

William M. Bumpers Megan H. Berge BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004

Tel: (202) 639-7700

william.bumpers@bakerbotts.com megan.berge@bakerbotts.com Counsel for Petitioner NorthWestern Corporation d/b/a NorthWestern Energy

Allison D. Wood Tauna M. Szymanski Andrew D. Knudsen HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 awood@hunton.com tszymanski@hunton.com aknudsen@hunton.com Counsel for Petitioner Tri-State Generation and Transmission Association, Inc.

William M. Bumpers Megan H. Berge BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004

Tel: (202) 639-7700

william.bumpers@bakerbotts.com megan.berge@bakerbotts.com Counsel for Petitioner Westar Energy, Inc.

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Jeffrey R. Holmstead Sandra Y. Snyder BRACEWELL & GIULIANI LLP 2000 K Street, N.W., Suite 500 Washington, D.C. 20006-1872 Tel: (202) 828-5852 Fax: (202) 857-4812 jeff.holmstead@bgllp.com Counsel for Petitioner American Coalition for Clean Coal Electricity

Geoffrey K. Barnes J. Van Carson Wendlene M. Lavey John D. Lazzaretti Robert D. Cheren SQUIRE PATTON BOGGS (US) LLP 4900 Key Tower 127 Public Square Cleveland, OH 44114 Tel: (216) 479-8646 geoffrey.barnes@squirepb.com Counsel for Petitioner Murray Energy Corporation

Andrew C. Emrich HOLLAND & HART LLP 6380 South Fiddlers Green Circle Suite 500 Greenwood Village, CO 80111 Tel: (303) 290-1621

Fax: (866) 711-8046

acemrich@hollandhart.com Emily C. Schilling HOLLAND & HART LLP 222 South Main Street, Suite 2200 Salt Lake City, UT 84101 Tel: (801) 799-5753 Fax: (202) 747-6574 ecschilling@hollandhart.com Counsel for Petitioners Newmont Nevada Energy Investment, LLC and Newmont USA Limited

Charles T. Wehland Counsel of Record Brian J. Murray JONES DAY 77 West Wacker Drive, Suite 3500 Chicago, IL 60601-1692 Tel: (312) 782-3939 Fax: (312) 782-8585 ctwehland@jonesday.com bjmurray@jonesday.com Counsel for Petitioners The North American Coal Corporation; The Coteau Properties Company; Coyote Creek Mining Company, LLC; The Falkirk Mining Company; Mississippi Lignite Mining Company; North American Coal Royalty Company; NODAK Energy Services, LLC; Otter Creek Mining Company, LLC; and The Sabine Mining Company

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Robert G. McLusky JACKSON KELLY, PLLC 1600 Laidley Tower P.O. Box 553 Charleston, WV 25322 Tel: (304) 340-1000 rmclusky@jacksonkelly.com Counsel for Petitioner West Virginia Coal Association

Eugene M. Trisko LAW OFFICES OF EUGENE M. TRISKO P.O. Box 596 Berkeley Springs, WV 25411 Tel: (304) 258-1977 Tel: (301) 639-5238 (cell) emtrisko7@gmail.com Counsel for Petitioner International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers & Helpers

Eugene M. Trisko LAW OFFICES OF EUGENE M. TRISKO P.O. Box 596 Berkeley Springs, WV 25411 Tel: (304) 258-1977 Tel: (301) 639-5238 (cell) emtrisko7@gmail.com Counsel for Petitioner International Brotherhood of Electrical Workers, AFL-CIO

Grant F. Crandall General Counsel UNITED MINE WORKERS OF AMERICA 18354 Quantico Gateway Drive

Triangle, VA 22172

Tel: (703) 291-2429 gcrandall@umwa.org Arthur Traynor, III Staff Counsel UNITED MINE WORKERS OF AMERICA 18354 Quantico Gateway Drive Triangle, VA 22172 Tel: (703) 291-2457 atraynor@umwa.org Eugene M. Trisko LAW OFFICES OF EUGENE M. TRISKO P.O. Box 596 Berkeley Springs, WV 25411 Tel: (304) 258-1977 emtrisko7@gmail.com Counsel for Petitioner United Mine Workers of America

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Megan H. Berge William M. Bumpers BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004

Tel: (202) 639-7700

megan.berge@bakerbotts.com william.bumpers@bakerbotts.com Counsel for Petitioner National Association of Home Builders

Scott M. DuBoff Matthew R. Schneider GARVEY SCHUBERT BARER 1000 Potomac Street, N.W., Suite 200 Washington, D.C. 20007 Tel: (202) 965-7880 sduboff@gsblaw.com Counsel for Petitioner Local Government Coalition for Renewable Energy

Kathryn D. Kirmayer General Counsel Evelyn R. Nackman Associate General Counsel ASSOCIATION OF AMERICAN RAILROADS 425 3rd Street, S.W. Washington, D.C. 20024 Tel: (202) 639-2100 kkirmayer@aar.org Counsel for Petitioner Association of American Railroads

Catherine E. Stetson Eugene A. Sokoloff HOGAN LOVELLS US LLP 555 Thirteenth Street, N.W. Washington, D.C. 20004-1109 Tel: (202) 637-5600 Fax: (202) 637-5910 cate.stetson@hoganlovells.com eugene.sokoloff@hoganlovells.com Counsel for Petitioner Denbury Onshore, LLC

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C. Boyden Gray Adam R.F. Gustafson Counsel of Record Derek S. Lyons James R. Conde BOYDEN GRAY & ASSOCIATES, PLLC 1627 I Street, N.W., #950

Washington, D.C. 20006

Tel: (202) 955-0620 gustafson@boydengrayassociates.com Sam Kazman Hans Bader COMPETITIVE ENTERPRISE INSTITUTE 1899 L Street, N.W., 12th Floor Washington, D.C. 20036 Tel: (202) 331-1010 Counsel for Petitioners Competitive Enterprise Institute; Buckeye Institute for Public Policy Solutions; Independence Institute; Rio Grande Foundation; Sutherland Institute; Klaus J. Christoph; Samuel R. Damewood; Catherine C. Dellin; Joseph W. Luquire; Lisa R. Markham; Patrick T. Peterson; and Kristi Rosenquist Robert Alt BUCKEYE INSTITUTE FOR PUBLIC POLICY

SOLUTIONS 88 E. Broad Street, Suite 1120 Columbus, OH 43215 Tel: (614) 224-4422 robert@buckeyeinstitute.org Counsel for Petitioner Buckeye Institute for Public Policy Solutions

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i

CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES

Pursuant to Circuit Rule 28(a)(1), Petitioners state as follows:

A. Parties, Intervenors, and Amici Curiae

These cases involve the following parties:

Petitioners:

No. 15-1363: State of West Virginia; State of Texas; State of Alabama;

State of Arizona Corporation Commission; State of Arkansas; State of Colorado; State

of Florida; State of Georgia; State of Indiana; State of Kansas; Commonwealth of

Kentucky; State of Louisiana; State of Louisiana Department of Environmental

Quality; Attorney General Bill Schuette, People of Michigan; State of Missouri; State

of Montana; State of Nebraska; State of New Jersey; State of North Carolina

Department of Environmental Quality; State of Ohio; State of South Carolina; State

of South Dakota; State of Utah; State of Wisconsin; and State of Wyoming.

No. 15-1364: State of Oklahoma ex rel. E. Scott Pruitt, in his official

capacity as Attorney General of Oklahoma and Oklahoma Department of

Environmental Quality.

No. 15-1365: International Brotherhood of Boilermakers, Iron Ship

Builders, Blacksmiths, Forgers & Helpers.

No. 15-1366: Murray Energy Corporation.

No. 15-1367: National Mining Association.

No. 15-1368: American Coalition for Clean Coal Electricity.

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No. 15-1370: Utility Air Regulatory Group and American Public Power

Association.

No. 15-1371: Alabama Power Company; Georgia Power Company; Gulf

Power Company; and Mississippi Power Company.

No. 15-1372: CO2 Task Force of the Florida Electric Power

Coordinating Group, Inc.

No. 15-1373: Montana-Dakota Utilities Co., a Division of MDU

Resources Group, Inc.

No. 15-1374: Tri-State Generation and Transmission Association, Inc.

No. 15-1375: United Mine Workers of America.

No. 15-1376: National Rural Electric Cooperative Association; Arizona

Electric Power Cooperative, Inc.; Associated Electric Cooperative, Inc.; Big Rivers

Electric Corporation; Brazos Electric Power Cooperative, Inc.; Buckeye Power, Inc.;

Central Montana Electric Power Cooperative; Central Power Electric Cooperative,

Inc.; Corn Belt Power Cooperative; Dairyland Power Cooperative; Deseret

Generation & Transmission Co-operative; East Kentucky Power Cooperative, Inc.;

East River Electric Power Cooperative, Inc.; East Texas Electric Cooperative, Inc.;

Georgia Transmission Corporation; Golden Spread Electrical Cooperative, Inc.;

Hoosier Energy Rural Electric Cooperative, Inc.; Kansas Electric Power Cooperative,

Inc.; Minnkota Power Cooperative, Inc.; North Carolina Electric Membership

Corporation; Northeast Texas Electric Cooperative, Inc.; Northwest Iowa Power

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Cooperative; Oglethorpe Power Corporation; PowerSouth Energy Cooperative;

Prairie Power, Inc.; Rushmore Electric Power Cooperative, Inc.; Sam Rayburn G&T

Electric Cooperative, Inc.; San Miguel Electric Cooperative, Inc.; Seminole Electric

Cooperative, Inc.; South Mississippi Electric Power Association; South Texas Electric

Cooperative, Inc.; Southern Illinois Power Cooperative; Sunflower Electric Power

Corporation; Tex-La Electric Cooperative of Texas, Inc.; Upper Missouri G. & T.

Electric Cooperative, Inc.; Wabash Valley Power Association, Inc.; Western Farmers

Electric Cooperative; and Wolverine Power Supply Cooperative, Inc.

No. 15-1377: Westar Energy, Inc.

No. 15-1378: NorthWestern Corporation d/b/a NorthWestern Energy.

No. 15-1379: National Association of Home Builders (“NAHB”).

No. 15-1380: State of North Dakota.

No. 15-1382: Chamber of Commerce of the United States of America;

National Association of Manufacturers; American Fuel & Petrochemical

Manufacturers; National Federation of Independent Business; American Chemistry

Council; American Coke and Coal Chemicals Institute; American Foundry Society;

American Forest & Paper Association; American Iron & Steel Institute; American

Wood Council; Brick Industry Association; Electricity Consumers Resource Council;

Lignite Energy Council; National Lime Association; National Oilseed Processors

Association; and Portland Cement Association.

No. 15-1383: Association of American Railroads.

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No. 15-1386: Luminant Generation Company LLC; Oak Grove

Management Company LLC; Big Brown Power Company LLC; Sandow Power

Company LLC; Big Brown Lignite Company LLC; Luminant Mining Company LLC;

and Luminant Big Brown Mining Company LLC.

No. 15-1393: Basin Electric Power Cooperative.

No. 15-1398: Energy & Environment Legal Institute.

No. 15-1409: Mississippi Department of Environmental Quality; State of

Mississippi; and Mississippi Public Service Commission.

No. 15-1410: International Brotherhood of Electrical Workers, AFL-

CIO.

No. 15-1413: Entergy Corporation.

No. 15-1418: LG&E and KU Energy LLC.

No. 15-1422: West Virginia Coal Association.

No. 15-1432: Newmont Nevada Energy Investment, LLC, and

Newmont USA Limited.

No. 15-1442: The Kansas City Board of Public Utilities – Unified

Government of Wyandotte County/Kansas City, Kansas.

No. 15-1451: The North American Coal Corporation; The Coteau

Properties Company; Coyote Creek Mining Company, LLC; The Falkirk Mining

Company; Mississippi Lignite Mining Company; North American Coal Royalty

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Company; NODAK Energy Services, LLC; Otter Creek Mining Company, LLC; and

The Sabine Mining Company.

No. 15-1459: Indiana Utility Group.

No. 15-1464: Louisiana Public Service Commission.

No. 15-1470: GenOn Mid-Atlantic, LLC; Indian River Power LLC;

Louisiana Generating LLC; Midwest Generation, LLC; NRG Chalk Point LLC; NRG

Power Midwest LP; NRG Rema LLC; NRG Texas Power LLC; NRG Wholesale

Generation LP; and Vienna Power LLC.

No. 15-1472: Prairie State Generating Company, LLC.

No. 15-1474: Minnesota Power (an operating division of ALLETE, Inc.).

No. 15-1475: Denbury Onshore, LLC.

No. 15-1477: Energy-Intensive Manufacturers Working Group on

Greenhouse Gas Regulation.

No. 15-1483: Local Government Coalition for Renewable Energy.

No. 15-1488: Competitive Enterprise Institute; Buckeye Institute for

Public Policy Solutions; Independence Institute; Rio Grande Foundation; Sutherland

Institute; Klaus J. Christoph; Samuel R. Damewood; Catherine C. Dellin; Joseph W.

Luquire; Lisa R. Markham; Patrick T. Peterson; and Kristi Rosenquist.

Respondents:

Respondents are the United States Environmental Protection Agency (in Nos.

15-1364, 15-1365, 15-1367, 15-1368, 15-1370, 15-1373, 15-1374, 15-1375, 15-1376,

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15-1380, 15-1383, 15-1398, 15-1410, 15-1418, 15-1442, 15-1472, 15-1474, 15-1475,

15-1483) and the United States Environmental Protection Agency and Gina

McCarthy, Administrator (in Nos. 15-1363, 15-1366, 15-1371, 15-1372, 15-1377, 15-

1378, 15-1379, 15-1382, 15-1386, 15-1393, 15-1409, 15-1413, 15-1422, 15-1432, 15-

1451, 15-1459, 15-1464, 15-1470, 15-1477, 15-1488).

Intervenors and Amici Curiae:

Dixon Bros., Inc.; Gulf Coast Lignite Coalition; Joy Global Inc.; Nelson

Brothers, Inc.; Norfolk Southern Corp.; Peabody Energy Corp.; and Western

Explosive Systems Company are Petitioner-Intervenors.

Advanced Energy Economy; American Lung Association; American Wind

Energy Association; Broward County, Florida; Calpine Corporation; Center for

Biological Diversity; City of Austin d/b/a Austin Energy; City of Boulder; City of

Chicago; City of Los Angeles, by and through its Department of Water and Power;

City of New York; City of Philadelphia; City of Seattle, by and through its City Light

Department; City of South Miami; Clean Air Council; Clean Wisconsin; Coal River

Mountain Watch; Commonwealth of Massachusetts; Commonwealth of Virginia;

Conservation Law Foundation; District of Columbia; Environmental Defense Fund;

Kanawha Forest Coalition; Keepers of the Mountains Foundation; Mon Valley Clean

Air Coalition; National Grid Generation, LLC; Natural Resources Defense Council;

New York Power Authority; NextEra Energy, Inc.; Ohio Environmental Council;

Ohio Valley Environmental Coalition; Pacific Gas and Electric Company; Sacramento

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Municipal Utility District; Sierra Club; Solar Energy Industries Association; Southern

California Edison Company; State of California by and through Governor Edmund

G. Brown, Jr., and the California Air Resources Board, and Attorney General Kamala

D. Harris; State of Connecticut; State of Delaware; State of Hawaii; State of Illinois;

State of Iowa; State of Maine; State of Maryland; State of Minnesota by and through

the Minnesota Pollution Control Agency; State of New Hampshire; State of New

Mexico; State of New York; State of Oregon; State of Rhode Island; State of

Vermont; State of Washington; and West Virginia Highlands Conservancy are

Respondent-Intervenors.

Philip Zoebisch; Pedernales Electric Cooperative, Inc.; Municipal Electric

Authority of Georgia; Pacific Legal Foundation; Texas Public Policy Foundation;

Morning Star Packing Company; Merit Oil Company; Loggers Association of

Northern California; and Norman R. “Skip” Brown are amici curiae in support of

Petitioners.

Former EPA Administrators William D. Ruckelshaus and William K. Reilly;

Institute for Policy Integrity at New York University School of Law; National League

of Cities; U.S. Conference of Mayors; Baltimore, MD; Boulder County, CO; Coral

Gables, FL; Grand Rapids, MI; Houston, TX; Jersey City, NJ; Los Angeles, CA;

Minneapolis, MN; Pinecrest, FL; Portland, OR; Providence, RI; Salt Lake City, UT;

San Francisco, CA; West Palm Beach, FL; American Thoracic Society; American

Medical Association; American College of Preventive Medicine; American College of

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Occupational and Environmental Medicine; and the Service Employees International

Union are amici curiae in support of Respondents. American Sustainable Business

Council and South Carolina Small Business Chamber of Commerce are movant amici

curiae in support of Respondent.

B. Rulings Under Review

These consolidated cases involve final agency action of the United States

Environmental Protection Agency titled, “Carbon Pollution Emission Guidelines for

Existing Stationary Sources: Electric Utility Generating Units,” and published on

October 23, 2015, at 80 Fed. Reg. 64,662.

C. Related Cases

These consolidated cases have not previously been before this Court or any

other court. Counsel is aware of five related cases that, as of the time of filing, have

appeared before this Court:

(1) In re Murray Energy Corporation, No. 14-1112,

(2) Murray Energy Corporation v. EPA, No. 14-1151 (consolidated with No. 14-1112),

(3) State of West Virginia v. EPA, No. 14-1146,

(4) In re: State of West Virginia, No. 15-1277, and

(5) In re Peabody Energy Corporation, No. 15-1284 (consolidated with No. 15-1277).

Per the Court’s order of January 21, 2016, the following cases are consolidated

and being held in abeyance pending potential administrative resolution of biogenic

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carbon dioxide emissions issues in the Final Rule: National Alliance of Forest Owners v.

EPA, No. 15-1478; Biogenic CO2 Coalition v. EPA, No. 15-1479; and American Forest &

Paper Association, Inc. and American Wood Council v. EPA, No. 15-1485.

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CORPORATE DISCLOSURE STATEMENTS

Non-governmental Petitioners submit the following statements pursuant to

Rule 26.1 of the Federal Rules of Appellate Procedure and Circuit Rule 26.1:

Alabama Power Company is a wholly-owned subsidiary of Southern Company, which is a publicly held corporation. Other than Southern Company, no publicly-held company owns 10% or more of Alabama Power Company’s stock. Southern Company is traded publicly on the New York Stock Exchange under the symbol “SO.” American Coalition for Clean Coal Electricity (“ACCCE”) is a partnership of companies that are involved in the production of electricity from coal. ACCCE recognizes the inextricable linkage between energy, the economy and our environment. Toward that end, ACCCE supports policies that promote the wise use of coal, one of America’s largest domestically produced energy resources, to ensure a reliable and affordable supply of electricity to meet our nation’s demand for energy. The ACCCE is a “trade association” within the meaning of Circuit Rule 26.1(b). It has no parent corporation, and no publicly held company owns a 10% or greater interest in the ACCCE. American Public Power Association (“APPA”) is the national association of publicly-owned electric utilities. APPA has no outstanding shares or debt securities in the hands of the public. APPA has no parent company. No publicly held company has a 10% or greater ownership in APPA. Arizona Electric Power Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Arizona Electric Power Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Associated Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Associated Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Association of American Railroads (“AAR”) is a nonprofit trade association whose members include all of the Class I freight railroads (the largest freight railroads), as well as some smaller freight railroads and Amtrak. AAR represents its member railroads in proceedings before Congress, the courts, and administrative agencies in matters of common interest, such as the issues that are the subject matter of this litigation. AAR is a “trade association” within the meaning of Circuit Rule 26.1(b). It

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has no parent corporation, and no publicly held company owns a 10% or greater interest in AAR. Basin Electric Power Cooperative (“Basin Electric”) is a not-for-profit regional wholesale electric generation and transmission cooperative owned by over 100 member cooperatives. Basin Electric provides wholesale power to member rural electric systems in nine states, with electric generation facilities in North Dakota, South Dakota, Wyoming, Montana, and Iowa serving approximately 2.9 million customers. Basin Electric has no parent companies. There are no publicly held corporations that have a 10% or greater ownership interest in Basin Electric. Big Brown Lignite Company, LLC is a wholly owned subsidiary of Luminant Holding Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Texas Competitive Electric Holdings Company LLC (“TCEH”). TCEH is a Delaware limited liability company and is a wholly owned subsidiary of Energy Future Competitive Holdings Company (“EFCH”), which is a Texas corporation and a wholly owned subsidiary of Energy Future Holdings Corp. (“EFH Corp.”). Substantially all of the common stock of EFH Corp., a Texas corporation, is owned by Texas Energy Future Holdings Limited Partnership, which is a privately held limited partnership. No publicly held entities have a 10% or greater equity ownership interest in EFH Corp. Big Brown Power Company, LLC is a wholly owned subsidiary of Luminant Holding Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Texas Competitive Electric Holdings Company LLC (“TCEH”). TCEH is a Delaware limited liability company and is a wholly owned subsidiary of Energy Future Competitive Holdings Company (“EFCH”), which is a Texas corporation and a wholly owned subsidiary of Energy Future Holdings Corp. (“EFH Corp.”). Substantially all of the common stock of EFH Corp., a Texas corporation, is owned by Texas Energy Future Holdings Limited Partnership, which is a privately held limited partnership. No publicly held entities have a 10% or greater equity ownership interest in EFH Corp. Big Rivers Electric Corporation has no parent corporation. No publicly held corporation owns any portion of Big Rivers Electric Corporation, and it is not a subsidiary or an affiliate of any publicly owned corporation. Brazos Electric Power Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Brazos Electric Power Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation.

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Buckeye Institute for Public Policy Solutions (“Buckeye Institute”) is a nonprofit organization incorporated in Ohio under Section 501(c)(3) of the Internal Revenue Code. The Buckeye Institute seeks to improve Ohio policies by performing research and promoting market-oriented policy solutions. No parent company or publicly-held company has a 10% or greater ownership interest in the Buckeye Institute. Buckeye Power, Inc. has no parent corporation. No publicly held corporation owns any portion of Buckeye Power, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Central Montana Electric Power Cooperative has no parent corporation. No publicly held corporation owns any portion of Central Montana Electric Power Cooperative, and it is not a subsidiary or an affiliate of any publicly owned corporation. Central Power Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Central Power Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. CO2 Task Force of the Florida Electric Power Coordinating Group, Inc. (“FCG”) is a non-profit, non-governmental corporate entity organized under the laws of Florida. The FCG does not have a parent corporation. No publicly held corporation owns 10% or more of the FCG’s stock. Competitive Enterprise Institute (“CEI”) is a nonprofit organization incorporated in Washington D.C. under Section 501(c)(3) of the Internal Revenue Code. CEI focuses on advancing market approaches to regulatory issues. No parent company or publicly-held company has a 10% or greater ownership interest in CEI. Corn Belt Power Cooperative has no parent corporation. No publicly held corporation owns any portion of Corn Belt Power Cooperative, and it is not a subsidiary or an affiliate of any publicly owned corporation. Coteau Properties Company (“Coteau Properties”) is a wholly-owned subsidiary of The North American Coal Corporation (“NACoal”). No publicly held entity has a 10% or greater ownership interest in Coteau Properties. The general nature and purpose of Coteau Properties, insofar as relevant to this litigation, is the mining and marketing of lignite coal as fuel for power generation in North Dakota. Coyote Creek Mining Company, LLC (“Coyote Creek Mining”) is a wholly-owned subsidiary of NACoal. No publicly held entity has a 10% or greater ownership interest

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in Coyote Creek Mining. The general nature and purpose of Coyote Creek Mining, insofar as relevant to this litigation, is the mining and marketing of lignite coal as fuel for power generation in North Dakota. Dairyland Power Cooperative has no parent corporation. No publicly held corporation owns any portion of Dairyland Power Cooperative, and it is not a subsidiary or an affiliate of any publicly owned corporation. Denbury Onshore, LLC is a wholly owned subsidiary of Denbury Resources Inc., a publicly held corporation whose shares are listed on the New York Stock Exchange. Other than Denbury Resources Inc., no publicly-held company owns 10% or more of any of Petitioner’s stock and no publicly-held company holds 10% or more of Denbury Resources, Inc., stock. The stock of Denbury Resources, Inc. is traded publicly on the New York Stock Exchange under the symbol “DNR.” Denbury is an oil and gas production company. As a part of its oil recovery operations (generally termed “tertiary” or “enhanced” recovery) that are performed in several states, Denbury, with its affiliated companies, produces, purchases, transports, and injects carbon dioxide for the purpose of the recovery of hydrocarbon resources. Deseret Generation & Transmission Co-operative has no parent corporation. No publicly held corporation owns any portion of Deseret Generation & Transmission Co-operative, and it is not a subsidiary or an affiliate of any publicly owned corporation. East Kentucky Power Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of East Kentucky Power Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. East River Electric Power Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of East River Electric Power Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. East Texas Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of East Texas Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Energy-Intensive Manufacturers Working Group on Greenhouse Gas Regulation (“EIM”) is a coalition of individual companies. EIM has no outstanding shares or debt securities in the hands of the public. EIM has no parent corporation, and no publicly held company has 10% or greater ownership in EIM.

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Entergy Corporation (“Entergy”) is a publicly traded company incorporated in the State of Delaware, with its principal place of business in the city of New Orleans, Louisiana. Entergy does not have any parent companies that have a 10% or greater ownership interest in Entergy. Further, there is no publicly-held company that has a 10% or greater ownership interest in Entergy. Entergy is an integrated energy company engaged primarily in electric power production and electric retail distribution operations. Entergy delivers electricity to approximately 2.8 million customers in Arkansas, Louisiana, Mississippi, and Texas. Falkirk Mining Company (“Falkirk Mining”) is a wholly-owned subsidiary of NACoal. No publicly held entity has a 10% or greater ownership interest in Falkirk Mining. The general nature and purpose of Falkirk Mining, insofar as relevant to this litigation, is the mining and marketing of lignite coal as fuel for power generation in North Dakota. GenOn Mid-Atlantic, LLC exists to provide safe, reliable, and affordable electric power to consumers. It is a limited liability corporation wholly owned by NRG North America LLC, a limited liability corporation wholly owned by GenOn Americas Generation, LLC. GenOn Americas Generation, LLC is a limited liability corporation wholly owned by NRG Americas, Inc. NRG Americas, Inc. is a corporation wholly owned by GenOn Energy Holdings, Inc., a corporation wholly owned by GenOn Energy, Inc. GenOn Energy, Inc. is a corporation wholly owned by NRG Energy, Inc. a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc., a publicly-traded company. Georgia Power Company is a wholly-owned subsidiary of Southern Company, which is a publicly held corporation. Other than Southern Company, no publicly-held company owns 10% or more of Georgia Power Company’s stock. Southern Company is traded publicly on the New York Stock Exchange under the symbol “SO.” Georgia Transmission Corporation has no parent corporation. No publicly held corporation owns any portion of Georgia Transmission Corporation, and it is not a subsidiary or an affiliate of any publicly owned corporation. Golden Spread Electrical Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Golden Spread Electrical Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation.

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Gulf Power Company is a wholly-owned subsidiary of Southern Company, which is a publicly held corporation. Other than Southern Company, no publicly-held company owns 10% or more of Gulf Power Company’s stock. Southern Company is traded publicly on the New York Stock Exchange under the symbol “SO.” Hoosier Energy Rural Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Hoosier Energy Rural Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Independence Institute is a nonprofit organization incorporated in Colorado under Section 501(c)(3) of the Internal Revenue Code. The Independence Institute is a public policy think tank whose purpose is to educate citizens, legislators, and opinion makers in Colorado about policies that enhance personal and economic freedom. No parent company or publicly-held company has a 10% or greater ownership interest in the Independence Institute. Indian River Power LLC exists to provide safe, reliable, and affordable electric power to consumers. It is a limited liability corporation wholly owned by NRG Energy, Inc., a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc. a publicly-traded company. Indiana Utility Group (“IUG”) is a continuing association of individual electric generating companies operated for the purpose of promoting the general interests of the membership of electric generators. IUG has no outstanding shares or debt securities in the hand of the public and has no parent company. No publicly held company has a 10% or greater ownership interest in IUG. International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers, and Helpers (“IBB”) is a non-profit national labor organization with headquarters in Kansas City, Kansas. IBB’s members are active and retired members engaged in various skilled trades of welding and fabrication of boilers, ships, pipelines, and other industrial facilities and equipment in the United States and Canada, and workers in other industries in the United States organized by the IBB. IBB provides collective bargaining representation and other membership services on behalf of its members. IBB is affiliated with the American Federation of Labor-Congress of Industrial Organizations. IBB and its affiliated lodges own approximately 60% of the outstanding stock of Brotherhood Bancshares, Inc., the holding company of the Bank

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of Labor. Bank of Labor’s mission is to serve the banking and other financial needs of the North American labor movement. No entity owns 10% or more of IBB. International Brotherhood of Electrical Workers, AFL-CIO (“IBEW”) is a non-profit national labor organization with headquarters located at 900 7th Street, N.W., Washington, D.C. 20001. IBEW’s members are active and retired skilled electricians and related professionals engaged in a broad array of U.S. industries, including the electrical utility, coal mining, and railroad transportation sectors that stand to be impacted adversely by implementation of EPA’s final agency action. IBEW provides collective bargaining representation and other membership services and benefits on behalf of its members. IBEW is affiliated with the American Federation of Labor-Congress of Industrial Organizations. IBEW has no parent companies, subsidiaries, or affiliates that have issued shares or debt securities to the public. Kansas Electric Power Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Kansas Electric Power Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. LG&E and KU Energy LLC is the holding company for Louisville Gas and Electric Company (“LG&E”) and Kentucky Utilities Company (“KU”), regulated utilities that serve a total of 1.2 million customers. LG&E serves 321,000 natural gas and 400,000 electric customers in Louisville, Kentucky and 16 surrounding counties, whereas KU serves 543,000 customers in 77 Kentucky counties and five counties in Virginia. LG&E and KU Energy LLC is a wholly-owned subsidiary of PPL Corporation. Other than PPL Corporation, no publicly-held company owns 10% or more of any of LG&E and KU Energy LLC’s membership interests. No publicly held company has a 10% or greater ownership interest in PPL Corporation. Local Government Coalition for Renewable Energy (“Coalition”) is a not-for-profit association of local government entities, including cities, counties and special purpose authorities. Working in coordination with the Municipal Waste Management Association, the environmental affiliate of the U.S. Conference of Mayors, the Coalition participates in state and federal regulatory proceedings, as well as judicial review proceedings, that affect operation of waste-to-energy facilities for management of municipal solid waste. None of the Coalition members have issued stock, partnership shares or any similar indicia of ownership interests, and none of the Coalition members have a parent corporation. As noted below, the Coalition joins this brief with respect to Arguments III.A and III.B. Louisiana Generating LLC exists to provide safe, reliable, and affordable electric power to consumers. It is a limited liability corporation wholly owned by NRG South

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Central Generating LLC, a limited liability corporation which in turn is wholly owned by NRG Energy, Inc., a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc. a publicly-traded company. Luminant Big Brown Mining Company, LLC is a wholly owned subsidiary of Luminant Holding Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Texas Competitive Electric Holdings Company LLC (“TCEH”). TCEH is a Delaware limited liability company and is a wholly owned subsidiary of Energy Future Competitive Holdings Company (“EFCH”), which is a Texas corporation and a wholly owned subsidiary of Energy Future Holdings Corp. (“EFH Corp.”). Substantially all of the common stock of EFH Corp., a Texas corporation, is owned by Texas Energy Future Holdings Limited Partnership, which is a privately held limited partnership. No publicly held entities have a 10% or greater equity ownership interest in EFH Corp. Luminant Generation Company, LLC is a wholly owned subsidiary of Luminant Holding Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Texas Competitive Electric Holdings Company LLC (“TCEH”). TCEH is a Delaware limited liability company and is a wholly owned subsidiary of Energy Future Competitive Holdings Company (“EFCH”), which is a Texas corporation and a wholly owned subsidiary of Energy Future Holdings Corp. (“EFH Corp.”). Substantially all of the common stock of EFH Corp., a Texas corporation, is owned by Texas Energy Future Holdings Limited Partnership, which is a privately held limited partnership. No publicly held entities have a 10% or greater equity ownership interest in EFH Corp. Luminant Mining Company, LLC is a wholly owned subsidiary of Luminant Holding Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Texas Competitive Electric Holdings Company LLC (“TCEH”). TCEH is a Delaware limited liability company and is a wholly owned subsidiary of Energy Future Competitive Holdings Company (“EFCH”), which is a Texas corporation and a wholly owned subsidiary of Energy Future Holdings Corp. (“EFH Corp.”). Substantially all of the common stock of EFH Corp., a Texas corporation, is owned by Texas Energy Future Holdings Limited Partnership, which is a privately held limited partnership. No publicly held entities have a 10% or greater equity ownership interest in EFH Corp.

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Midwest Generation LLC exists to provide safe, reliable, and affordable electric power to consumers. It is a limited liability corporation wholly owned by Midwest Generation Holdings II, LLC. Midwest Generation Holdings II, LLC is a limited liability corporation wholly owned by Midwest Generation Holdings I, LLC. Midwest Generation Holdings I, LLC is a limited liability corporation 95% of which is owned by Mission Midwest Coal, LLC and 5% of which is owned by Midwest Generation Holdings Limited, which in turn is wholly owned by Mission Midwest Coal, LLC. Mission Midwest Coal, LLC is a limited liability corporation wholly owned by NRG Midwest Holdings LLC, which in turn is a limited liability corporation wholly owned by Midwest Generation EME, LLC. Midwest Generation EME, LLC is a limited liability corporation wholly owned by NRG Energy Holdings Inc. which is a corporation wholly owned by NRG Acquisition Holdings Inc. NRG Acquisition Holdings is a corporation wholly owned by NRG Energy, Inc., a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc. a publicly-traded company. Minnesota Power is an operating division of ALLETE, Inc. No publicly-held company has a 10% or greater ownership interest in ALLETE, Inc. Minnkota Power Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Minnkota Power Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Mississippi Lignite Mining Company (“Mississippi Lignite Mining”) is a wholly-owned subsidiary of NACoal. No publicly held entity has a 10% or greater ownership interest in Mississippi Lignite Mining. The general nature and purpose of Mississippi Lignite Mining, insofar as relevant to this litigation, is the mining and marketing of lignite coal as fuel for power generation in Mississippi. Mississippi Power Company is a wholly-owned subsidiary of Southern Company, which is a publicly held corporation. Other than Southern Company, no publicly-held company owns 10% or more of Mississippi Power Company’s stock. Southern Company is traded publicly on the New York Stock Exchange under the symbol “SO.” Montana-Dakota Utilities Co. is engaged in the distribution of natural gas and the generation, transmission, and distribution of electricity in the states of North Dakota, South Dakota, Montana, and Wyoming. Montana-Dakota Utilities Co. is a division of

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MDU Resources Group, Inc. No publicly held company has a 10% or greater ownership interest in MDU Resources Group, Inc. Murray Energy Corporation has no parent corporation and no publicly held corporation owns 10% or more of its stock. Murray Energy Corporation is the largest privately-held coal company and largest underground coal mine operator in the United States. National Association of Home Builders (“NAHB”) is a not-for-profit trade association organized under the laws of Nevada. NAHB does not have any parent companies that have a 10% or greater ownership interest in NAHB. Further, there is no publicly-held company that has a 10% or greater ownership interest in NAHB. NAHB has issued no shares of stock to the public. NAHB is comprised of approximately 800 state and local home builders associations with whom it is affiliated, but all of those associations are, to the best of NAHB’s knowledge, nonprofit corporations that have not issued stock to the public. NAHB’s purpose is to promote the general commercial, professional, and legislative interests of its approximately 140,000 builder and associate members throughout the United States. NAHB’s membership includes entities that construct and supply single-family homes, as well as apartment, condominium, multi-family, commercial, and industrial builders, land developers, and remodelers. National Rural Electric Cooperative Association has no parent corporation. No publicly held corporation owns any portion of National Rural Electric Cooperative Association, and it is not a subsidiary or an affiliate of any publicly owned corporation. Newmont Nevada Energy Investment, LLC is a wholly-owned subsidiary of Newmont USA Limited and is the owner and operator of the TS Power Plant, a 242 MW coal-fired power plant located in Eureka County, Nevada, which provides power to Newmont USA Limited’s mining operations. No other publicly held corporation owns 10% or more of the stock of Newmont Nevada Energy Investment, LLC. Newmont USA Limited owns and operates 11 surface gold and copper mines, eight underground mines, and 13 processing facilities in Nevada that are served by the TS Power Plant. Newmont USA Limited is a wholly owned subsidiary of Newmont Mining Corporation and no other publicly held corporation owns 10% or more of its stock. NODAK Energy Services, LLC (“NODAK”) is a wholly-owned subsidiary of NACoal. No publicly held entity has a 10% or greater ownership interest in NODAK.

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The general nature and purpose of NODAK, insofar as relevant to this litigation, is the operation of a lignite benefication facility within Great River Energy’s Coal Creek Station, a lignite-fired power generating station in North Dakota. The North American Coal Corporation (“NACoal”) is a wholly-owned subsidiary of NACCO Industries, Inc. NACoal is not publicly held, but NACCO Industries, Inc., its parent, is a publicly traded corporation that owns more than 10% of the stock of NACoal. No other publicly-held corporation owns more than 10% of the stock of NACoal. The general nature and purpose of NACoal, insofar as relevant to this litigation, is the mining and marketing of lignite coal as fuel for power generation and the provision of mining services to natural resources companies. North American Coal Royalty Company (“North American Coal Royalty”) is a wholly-owned subsidiary of NACoal. No publicly held entity has a 10% or greater ownership interest in North American Coal Royalty. The general nature and purpose of North American Coal Royalty, insofar as relevant to this litigation, is the acquisition and disposition of mineral and surface interests in support of NACoal’s mining of lignite coal as fuel for power generation and the provision of mining services to natural resources companies. North Carolina Electric Membership Corporation has no parent corporation. No publicly held corporation owns any portion of North Carolina Electric Membership Corporation, and it is not a subsidiary or an affiliate of any publicly owned corporation. Northeast Texas Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Northeast Texas Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Northwest Iowa Power Cooperative has no parent corporation. No publicly held corporation owns any portion of Northwest Iowa Power Cooperative, and it is not a subsidiary or an affiliate of any publicly owned corporation. NorthWestern Corporation is a publicly traded company (NYSE: NWE) incorporated in the State of Delaware with corporate offices in Butte, Montana and Sioux Falls, South Dakota. NorthWestern Corporation has no parent corporation. As of February 17, 2016, based on a review of statements filed with the Securities and Exchange Commission pursuant to Sections 13(d), 13(f), and 13(g) of the Securities and Exchange Act of 1934, as amended, BlackRock Fund Advisors is the only shareholder owning more than 10% or more of NorthWestern Corporation’s stock.

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In addition to publicly traded stock, NorthWestern Corporation has issued debt and bonds to the public. NRG Chalk Point LLC exists to provide safe, reliable, and affordable electric power to consumers. It is wholly owned by GenOn Mid-Atlantic, LLC. GenOn Mid-Atlantic, LLC is a limited liability corporation wholly owned by NRG North America LLC, a limited liability corporation wholly owned by GenOn Americas Generation, LLC. GenOn Americas Generation, LLC is a limited liability corporation wholly owned by NRG Americas, Inc. NRG Americas, Inc. is a corporation wholly owned by GenOn Energy Holdings, Inc., a corporation wholly owned by GenOn Energy, Inc. GenOn Energy, Inc. is a corporation wholly owned by NRG Energy, Inc., a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc. a publicly-traded company. NRG Power Midwest LP exists to provide safe, reliable, and affordable electric power to consumers. It is a limited partnership 99% of which is owned by NRG Power Generation Assets LLC and 1% of which is owned by NRG Power Midwest GP LLC, a limited liability corporation wholly owned by NRG Power Generation Assets LLC. NRG Power Generation Assets LLC is a limited liability corporation wholly owned by NRG Power Generation LLC, which is a limited liability corporation wholly owned by NRG Americas, Inc. NRG Americas, Inc. is a corporation wholly owned by GenOn Energy Holdings, Inc., a corporation wholly owned by GenOn Energy, Inc. GenOn Energy, Inc. is a corporation wholly owned by NRG Energy, Inc., a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc. a publicly-traded company. NRG Rema LLC exists to provide safe, reliable, and affordable electric power to consumers. It is a limited liability corporation wholly owned by NRG Northeast Generation, Inc., a corporation wholly owned by NRG Northeast Holdings Inc. NRG Northeast Holdings Inc. is a corporation wholly owned by NRG Power Generation LLC, a limited liability corporation wholly owned by NRG Americas, Inc. NRG Americas, Inc. is a corporation wholly owned by GenOn Energy Holdings, Inc., a corporation wholly owned by GenOn Energy, Inc. GenOn Energy, Inc. is a corporation wholly owned by NRG Energy, Inc., a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting

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period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc. a publicly-traded company. NRG Texas Power LLC exists to provide safe, reliable, and affordable electric power to consumers. It is a limited liability corporation wholly owned by NRG Texas LLC, which in turn is a limited liability corporation wholly owned by NRG Energy, Inc., a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc. a publicly-traded company. NRG Wholesale Generation LP exists to provide safe, reliable, and affordable electric power to consumers. It is a limited partnership 99% owned by NRG Power Generation Assets LLC and 1% owned by NRG Wholesale Generation GP LLC, both of which are wholly owned by NRG Power Generation LLC. NRG Power Generation LLC is a limited liability corporation wholly owned by NRG Americas, Inc. NRG Americas, Inc. is a corporation wholly owned by GenOn Energy Holdings, Inc., a corporation wholly owned by GenOn Energy, Inc. GenOn Energy, Inc. is a corporation wholly owned by NRG Energy, Inc., a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc. a publicly-traded company. Oak Grove Management Company, LLC is a wholly owned subsidiary of Luminant Holding Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Texas Competitive Electric Holdings Company LLC (“TCEH”). TCEH is a Delaware limited liability company and is a wholly owned subsidiary of Energy Future Competitive Holdings Company (“EFCH”), which is a Texas corporation and a wholly owned subsidiary of Energy Future Holdings Corp. (“EFH Corp.”). Substantially all of the common stock of EFH Corp., a Texas corporation, is owned by Texas Energy Future Holdings Limited Partnership, which is a privately held limited partnership. No publicly held entities have a 10% or greater equity ownership interest in EFH Corp. Oglethorpe Power Corporation has no parent corporation. No publicly held corporation owns any portion of Oglethorpe Power Corporation, and it is not a subsidiary or an affiliate of any publicly owned corporation.

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Otter Creek Mining Company, LLC (“Otter Creek”) is a wholly-owned subsidiary of NACoal. No publicly held entity has a 10% or greater ownership interest in Otter Creek. The general nature and purpose of Otter Creek, insofar as relevant to this litigation, is the development of a mine to deliver lignite coal as fuel for power generation in North Dakota. PowerSouth Energy Cooperative has no parent corporation. No publicly held corporation owns any portion of PowerSouth Energy Cooperative, and it is not a subsidiary or an affiliate of any publicly owned corporation. Prairie Power, Inc. has no parent corporation. No publicly held corporation owns any portion of Prairie Power, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Prairie State Generating Company, LLC (“PSGC”) is a private non-governmental corporation that is principally engaged in the business of generating electricity for cooperatives and public power companies. PSGC does not have a parent corporation and no publicly-held corporation owns ten% or more of its stock. Rio Grande Foundation is a nonprofit organization incorporated in New Mexico under Section 501(c)(3) of the Internal Revenue Code. The Rio Grande Foundation is a research institute dedicated to increasing liberty and prosperity for New Mexico’s citizens. No parent company or publicly-held company has a 10% or greater ownership interest in the Rio Grande Foundation. Rushmore Electric Power Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Rushmore Electric Power Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. The Sabine Mining Company (“Sabine Mining”) is a wholly-owned subsidiary of NACoal. No publicly held entity has a 10% or greater ownership interest in Sabine Mining. The general nature and purpose of Sabine Mining, insofar as relevant to this litigation, is the mining of lignite coal as fuel for power generation in Texas. Sam Rayburn G&T Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Sam Rayburn G&T Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation.

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San Miguel Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of San Miguel Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Sandow Power Company, LLC is a wholly owned subsidiary of Luminant Holding Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Texas Competitive Electric Holdings Company LLC (“TCEH”). TCEH is a Delaware limited liability company and is a wholly owned subsidiary of Energy Future Competitive Holdings Company (“EFCH”), which is a Texas corporation and a wholly owned subsidiary of Energy Future Holdings Corp. (“EFH Corp.”). Substantially all of the common stock of EFH Corp., a Texas corporation, is owned by Texas Energy Future Holdings Limited Partnership, which is a privately held limited partnership. No publicly held entities have a 10% or greater equity ownership interest in EFH Corp. Seminole Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Seminole Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. South Mississippi Electric Power Association has no parent corporation. No publicly held corporation owns any portion of South Mississippi Electric Power Association, and it is not a subsidiary or an affiliate of any publicly owned corporation. South Texas Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of South Texas Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Southern Illinois Power Cooperative has no parent corporation. No publicly held corporation owns any portion of Southern Illinois Power Cooperative, and it is not a subsidiary or an affiliate of any publicly owned corporation. Sunflower Electric Power Corporation has no parent corporation. No publicly held corporation owns any portion of Sunflower Electric Power Corporation, and it is not a subsidiary or an affiliate of any publicly owned corporation. Sutherland Institute is a nonprofit organization incorporated in Utah under Section 501(c)(3) of the Internal Revenue Code. The Sutherland Institute is a public policy think tank committed to influencing Utah law and policy based on the core principles of limited government, personal responsibility, and charity. No parent company or

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publicly-held company has a 10% or greater ownership interest in the Sutherland Institute. Tex-La Electric Cooperative of Texas, Inc. has no parent corporation. No publicly held corporation owns any portion of Tex-La Electric Cooperative of Texas, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Tri-State Generation and Transmission Association, Inc. (“Tri-State”) is a wholesale electric power supply cooperative which operates on a not-for-profit basis and is owned by 1.5 million member-owners and 44 distribution cooperatives. Tri-State issues no stock and has no parent corporation. Accordingly, no publicly held corporation owns 10% or more of its stock. United Mine Workers of America (“UMWA”) is a non-profit national labor organization with headquarters in Triangle, Virginia. UMWA’s members are active and retired miners engaged in the extraction of coal and other minerals in the United States and Canada, and workers in other industries in the United States organized by the UMWA. UMWA provides collective bargaining representation and other membership services on behalf of its members. UMWA is affiliated with the America Federation of Labor-Congress of Industrial Organizations. UMWA has no parent companies, subsidiaries, or affiliates that have issued shares or debt securities to the public. Upper Missouri G. & T. Electric Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Upper Missouri G. & T. Electric Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. Utility Air Regulatory Group (“UARG”) is a not-for-profit association of individual generating companies and national trade associations that participates on behalf of its members collectively in administrative proceedings under the Clean Air Act, and in litigation arising from those proceedings, that affect electric generators. UARG has no outstanding shares or debt securities in the hands of the public and has no parent company. No publicly held company has a 10% or greater ownership interest in UARG. Vienna Power LLC exists to provide safe, reliable, and affordable electric power to consumers. It is a limited liability corporation wholly owned by NRG Energy, Inc., a Delaware publicly-traded corporation. NRG Energy, Inc. has no parent corporation. As of the last reporting period, T. Rowe Price Associates, Inc. held a 10% or greater ownership in NRG Energy, Inc. As of the last reporting period, T. Rowe Price

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Associates, Inc. was a subsidiary of T. Rowe Price Group, Inc. a publicly-traded company. Wabash Valley Power Association, Inc. has no parent corporation. No publicly held corporation owns any portion of Wabash Valley Power Association, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation. West Virginia Coal Association (“WVCA”) is a trade association representing more than 90% of West Virginia’s underground and surface coal mine production. No publicly-held company has 10% or greater ownership of the WVCA. Western Farmers Electric Cooperative has no parent corporation. No publicly held corporation owns any portion of Western Farmers Electric Cooperative, and it is not a subsidiary or an affiliate of any publicly owned corporation. Westar Energy, Inc. (“Westar”) is a publicly traded company (symbol: WR) incorporated in the State of Kansas, with its principal place of business in the city of Topeka, Kansas. Westar is the parent corporation of Kansas Gas and Electric Company (“KGE”), a Kansas corporation with its principal place of business in Topeka, Kansas. Westar owns all of the stock of KGE. In addition to Westar’s publicly traded stock, both Westar and KGE have issued debt and bonds to the public. Westar does not have any parent companies that have a 10% or greater ownership interest in Westar. Further, there is no publicly-held company that has a 10% or greater ownership interest in Westar. Wolverine Power Supply Cooperative, Inc. has no parent corporation. No publicly held corporation owns any portion of Wolverine Power Supply Cooperative, Inc., and it is not a subsidiary or an affiliate of any publicly owned corporation.

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TABLE OF CONTENTS

CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES ......................................................................................................................... i

A. Parties, Intervenors, and Amici Curiae .......................................................... i

B. Rulings Under Review ............................................................................... viii

C. Related Cases .............................................................................................. viii

CORPORATE DISCLOSURE STATEMENTS............................................................ x

GLOSSARY OF TERMS .................................................................................................. xl

JURISDICTIONAL STATEMENT ............................................................................... xli

STANDING STATEMENT .......................................................................................... xlii

STATEMENT OF ISSUES ............................................................................................... 1

STATUTES AND REGULATIONS ............................................................................... 2

INTRODUCTION.............................................................................................................. 2

STATEMENT OF THE CASE ........................................................................................ 3

I. THE PROPOSED RULE ....................................................................................... 3

II. THE RULE ............................................................................................................... 5

A. Nationally Uniform Performance Rates ..................................................... 6

B. BSER Determination and Building Block Targets .................................... 7

C. The Integral Role of Trading Programs ..................................................... 9

SUMMARY OF ARGUMENT ....................................................................................... 11

ARGUMENT ..................................................................................................................... 13

I. EPA VIOLATED SECTION 307 BY PROMULGATING A NEVER-PROPOSED RULE. ............................................................................. 13

A. The Rule Is Fundamentally Different From The Proposal. .................. 13

B. EPA’s Circumvention of the Rulemaking Process Requires Vacatur. ......................................................................................................... 15

II. EPA’S BSER IS NOT “ADEQUATELY DEMONSTRATED” AND ITS EMISSION GUIDELINES ARE NOT “ACHIEVABLE” UNDER SECTION 111. ..................................................... 17

A. EPA Must Show Both “Adequate Demonstration” Of The BSER And “Achievability” Of The Emission Guidelines. .................... 17

B. EPA Failed To Satisfy Its Burdens. .......................................................... 19

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1. EPA Has Not Shown That Any Of Its Three Building Blocks Is Adequately Demonstrated Or Achievable. ........................................................................................ 22

a. Building Block 1. .................................................................. 22

b. Building Block 2. .................................................................. 27

(i) EPA Failed To Support Its Target For Increased Utilization Of Existing Gas Units. .......................................................................... 27

(ii) EPA Erroneously Counted “Unused” Capacity From Under-Construction Units. .......................................................................... 31

(iii) EPA Erred By Relying On Capacity From Gas-Fired Units’ Duct Burners For Redispatch. ......................................................... 32

c. Building Block 3. .................................................................. 33

d. EPA Failed To Account For Application Of BSER On Generating Units’ Emission Rates. .................. 37

2. EPA Has Failed To Account For Grid Reliability Or Infrastructure Needs. ....................................................................... 38

a. EPA Failed To Meaningfully Assess The Need To Build New Infrastructure. ................................... 38

b. EPA Failed To Ensure Reliable Electric Supply. ................................................................................... 40

(i) The Electric Reliability Council Of Texas ........................................................................... 43

(ii) Cooperatives .............................................................. 45

3. EPA’s BSER Is Not “Demonstrated” Or “Achievable” By Individual Sources. ............................................. 48

4. The Rule is Not Saved by the Presumed Availability of a Trading Program. ..................................................................... 49

C. EPA Imposes on States an Impossible Task of Implementing BSER to Achieve Required Emission Reductions. ................................................................................................... 53

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III. THE RULE ARBITRARILY PENALIZES MANY SOURCES OF LOW- AND NON-EMITTING GENERATION ALONG WITH COMPANIES AND STATES THAT HAVE ALREADY TAKEN COSTLY ACTIONS TO REDUCE EMISSIONS OF GREENHOUSE GASES. .................................................................................... 56

A. EPA Arbitrarily Ignores A Large Part Of The Electric Supply System For Compliance Purposes. ............................................. 561

B. The Rule Arbitrarily Discriminates Between Low- and Zero-Emitting Sources Built Before And After January 1, 2013. .............................................................................................................. 58

C. EPA Unlawfully Prohibits The Use of Enhanced Oil Recovery That Also Results In Associated CO2 Storage........................ 64

IV. EPA HAS FAILED TO CONSIDER IMPORTANT ASPECTS OF THE RULE. ..................................................................................................... 65

A. The Rule Impermissibly Regulates New Units. ....................................... 65

B. EPA Failed to Establish The Necessary Subcategories For Coal Types And Generation Technologies. ............................................. 67

C. EPA Failed to Consider Renewable Energy’s Limitations. .................... 68

D. EPA’s Cost-Benefit Analysis Is Fundamentally Flawed. ........................ 69

V. THE RULE SHOULD HAVE BEEN TAILORED TO INDIVIDUAL STATE CIRCUMSTANCES. ................................................... 72

A. In Calculating Wisconsin’s Baseline Emissions, EPA Improperly Disregarded A Nuclear Plant’s Imminent Retirement. ................................................................................................... 72

B. EPA Failed To Truly Account For Trading Between States And Indian Tribes in Arizona And Utah. ................................................ 73

C. EPA Ignored Wyoming’s Unique Circumstances. ................................ 752

D. The Rule Would Cause Particular Harm to Utah. ................................... 77

1. Utah’s Targets Are Unrepresentative Of Historic Utah Emissions. ............................................................................... 77

1 The Local Government Coalition for Renewable Energy joins this brief with respect to

Arguments III.A and III.B only. 2 Argument V.C is advanced only by the States of Wyoming and North Dakota.

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2. The Rule Unlawfully Impedes Utah’s Ability to Protect Its Most Sensitive Air Shed. .............................................. 79

E. EPA Failed To Take Into Account States Like New Jersey That Have Chosen To Deregulate Energy Services................................ 80

F. EPA Arbitrarily Excluded From Consideration Prior Emissions Reductions Achieved In North Carolina. .............................. 82

CONCLUSION ................................................................................................................. 84

CERTIFICATE OF COMPLIANCE

CERTIFICATE OF SERVICE

ADDENDUM

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TABLE OF AUTHORITIES

Page(s)

Cases

Am. Lung Ass’n. v. EPA, 134 F.3d 388 (D.C. Cir. 1998) ....................................................................................... 65

*Chevron v. Natural Res. Def. Council, 467 U.S. 837 (1984) ........................................................................................................ 66

*Conn. Light & Power Co. v. NRC, 673 F.2d 525 (D.C. Cir. 1982) ....................................................................................... 13

Conner v. Burford, 848 F.2d 1441 (9th Cir. 1988) ....................................................................................... 76

Del. Dept. of Natural Res. & Envtl. Control v. EPA, 785 F.3d 1 (D.C. Cir. 2015) ..................................................................................... 45, 62

*Envtl. Integrity Project v. EPA, 425 F.3d 992 (D.C. Cir. 2005) ................................................................................. 15, 16

*Essex Chem. Corp. v. Ruckelhaus, 486 F.2d 427 (D.C. Cir. 1973) ........................................................................... 18, 19, 20

Home Box Office, Inc. v. FCC, 567 F.2d 9 (D.C. Cir. 1977) ........................................................................................... 73

Indep. Petrol. Ass’n of Am. v. Babbitt, 92 F.3d 1248 (D.C. Cir. 1996) ................................................................................. 60, 73

Kooritzky v. Reich, 17 F.3d 1509 (D.C. Cir. 1994) ....................................................................................... 16

*Authorities upon which we chiefly rely are marked with asterisks.

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Kreis v. Sec’y of Air Force, 406 F.3d 684 (D.C. Cir. 2005) ....................................................................................... 73

*Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999) ................................................................................. 18, 21

McDonnell Douglas Corp. v. U.S. Dept. of the Air Force, 375 F.3d 1182 (D.C. Cir. 2004) ..................................................................................... 62

MCI Telecomms. Corp. v. FCC, 57 F.3d 1136 (D.C. Cir. 1995) ....................................................................................... 16

Michigan v. EPA, 135 S. Ct. 2699 (2015) .................................................................................................... 69

*Motor Vehicle Mfrs. Ass’n. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29 (1983) ....................................................................................... 58, 65, 71, 73

*Nat’l Ass’n of Home Builders v. EPA, 682 F.3d 1032 (D.C. Cir. 2012) ..................................................................................... 71

*Nat’l Lime Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980) ........................................... 17, 19, 21, 22, 25, 49, 50, 53

*Portland Cement Ass’n v. Ruckelhaus, 486 F.2d 375 (D.C. Cir. 1973) ........................................................................... 18, 33, 51

SEC v. Chenery Corp., 332 U.S. 194 (1947) ........................................................................................................ 65

Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) ....................................................................................... 19

*Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506 (D.C. Cir. 1983) ................................................................................. 16, 20

*Unbelievable, Inc. v. N.L.R.B., 118 F.3d 795 (D.C. Cir. 1997) ....................................................................................... 20

*Authorities upon which we chiefly rely are marked with asterisks.

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Statutes

7 U.S.C. § 901, et seq. ............................................................................................................ 45

16 U.S.C. § 824(b) ................................................................................................................. 45

Clean Air Act, 42 U.S.C. §§ 7401, et seq. (2014) .................................................................. 1

CAA § 101(b), 42 U.S.C. § 7401(b) ........................................................................... 70

*CAA § 111, 42 U.S.C. § 7411 ........................................................................... 1, 3, 17

CAA § 111(a), 42 U.S.C. § 7411(a) ...................................................................... 17, 69

CAA § 111(a)(1), 42 U.S.C. § 7411(a)(1) ....................................................... 17, 18, 50

CAA § 111(a)(2). 42 U.S.C. § 7411(a)(2) ................................................................... 66

CAA § 111(a)(6), 42 U.S.C. § 7411(a)(6) ................................................................... 66

CAA § 111(b), 42 U.S.C. § 7411(b) ................................................................. 1, 65, 66

CAA § 111(b)(2), 42 U.S.C. § 7411(b)(2) .................................................................. 67

*CAA § 111(d), 42 U.S.C. § 7411(d) ................................ 2, 48, 53, 55, 65, 66, 67, 73

CAA § 112, 42 U.S.C. § 7412 ..................................................................................... 67

CAA § 115, 42 U.S.C. § 7415 ..................................................................................... 70

*CAA § 307, 42 U.S.C. § 7607 ................................................................................... 13

*CAA § 307(d)(3), 42 U.S.C. § 7607(d)(3) ................................................................ 15

*CAA § 307(d)(3)(A)-(C), 42 U.S.C. § 7607(d)(3)(A)-(C) ....................................... 15

CAA §§ 401-416, 42 U.S.C. §§ 7651a-o .................................................................... 51

*Authorities upon which we chiefly rely are marked with asterisks.

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Electric Discount & Energy Competition Act, N.J.S.A. 48:3-49 et seq. ................... 80, 81

Endangered Species Act, 16 U.S.C. §§ 1531-1544 ............................................... 75, 76, 82

N.C. Gen. Stat. § 143-215.107D(b)-(e) .............................................................................. 82

N.J.A.C. 14:8-2.1 ................................................................................................................... 81

N.J. Admin. Code 14:8-2.3 .................................................................................................. 81

N.J. Admin. Code 14:8-2.3(a), (k) ....................................................................................... 81

N.J. Stat. Ann. 48:3-51 ......................................................................................................... 82

N.J. Stat. Ann. 48:3-87(d) .................................................................................................... 81

Tex. Util. Code Ann. § 39.001 ............................................................................................ 44

Federal Regulations

40 C.F.R. Part 60, Subpart UUUU ................................................................................... 2, 6

40 C.F.R. Part 98, Subpart UU ........................................................................................... 64

40 C.F.R. § 60.22(b)(5) ......................................................................................................... 67

40 C.F.R. § 60.40Da(a)(1) .................................................................................................... 15

40 C.F.R. § 60.41Da ............................................................................................................. 15

40 C.F.R. § 60.5750(d) ......................................................................................................... 52

40 C.F.R. § 60.5790(c)(1) ..................................................................................................... 10

40 C.F.R. § 60.5800(a)(1) ..................................................................................................... 56

40 C.F.R. § 60.5800(a)(1) .................................................................................................... 52

40 C.F.R. § 60.5800(a)(3) ..................................................................................................... 52

40 C.F.R. § 60.5800(a)(4)(iii) ............................................................................................... 62

40 C.F.R. § 60.5800(c)(3) ..................................................................................................... 52

40 C.F.R. § 60.5845 .............................................................................................................. 15

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40 C.F.R. § 60.5860(f)(2) ..................................................................................................... 64

40 C.F.R. § 60.57954(b) ....................................................................................................... 36

50 C.F.R. § 402.14(k) ............................................................................................................ 77

Federal Register

44 Fed. Reg. 33,580 (June 11, 1979) ................................................................................... 15

74 Fed. Reg. 66,496 (Dec. 15, 2009) .................................................................................. 70

77 Fed. Reg. 9,304 (Feb. 16, 2012) ..................................................................................... 67

77 Fed. Reg. 22,392 (April 13, 2012) .................................................................................. 17

79 Fed. Reg. 1,352 (Jan. 8, 2014) ........................................................................................ 17

79 Fed. Reg. 1,430 (Jan. 8, 2014) ............................................................................ 14, 17, 64

*79 Fed. Reg. 34,830 (June 18, 2014) ............................... 3, 4, 5, 14, 15, 37, 45, 64, 72, 75

79 Fed. Reg. 65,292 (Oct. 26, 2015) ................................................................................... 80

80 Fed. Reg. 24,914 (May 1, 2015) ..................................................................................... 77

*80 Fed. Reg. 64,662 (Oct. 23, 2015) .......................... 6, 7, 8, 9, 10, 13, 22, 23, 24, 25, 27, ........................................................................... 51, 52, 56, 57, 58, 60, 61, 63, 65, 67, 68, ......................................................................................... 71, 72, 74, 75, 76, 77, 78, 79, 83

80 Fed. Reg. 64,966 (Oct. 23, 2015) ......................................................................... 9, 66, 74

*Authorities upon which we chiefly rely are marked with asterisks.

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Miscellaneous

58 C.J.S. Mines and Minerals § 403 .................................................................................... 64

2015 Standard Scenarios Annual Report: U.S. Electric Sector Scenario Exploration. National Renewable Energy Laboratory at 19, http://www.nrel.gov/docs/fy15osti/64072.pdf ........................................................ 75

21st Century Energy, “What’s In a Target,” 13-15 (Jan. 2016), http://www.energyxxi.org/sites/ default/files/What%27s%20In%20a%20Target%20FINAL.pdf ............................ 34

Air Emissions from MSW Facilities, EPA, http://www3.epa.gov/epawaste/nonhaz/municipal/wte/airem.htm#7; .............. 61

Arizona Electric Power Co. Comments, EPA-HQ-OAR-2013-0602-22972 ......... 46, 47

Bridging the Gap, UNEP http://www.unep.org/pdf/UNEP_bridging_gap.pdf .............................................. 61

CO2 Emission Performance Rate and Goal Computation Technical Support Document for CPP Final Rule, EPA-HQ-OAR-2013-0602, 3850 ............................ 9

Dep’t of Interior, Federal Coal Leases COC-0123475 01 and COC-68590, (Jan. 2016), http://www.wrcc.osmre.gov/initiatives/ colowyo/documents/Colowyo_Collom_EA_CH%201-7.pdf ................................ 69

EIA Annual Energy Outlook 2015, EPA-HQ-OAR-2013-0602-36563 ....................... 34

EIA, Electric Power Monthly (Feb. 2014), EPA-HQ-OAR-2013-0602-0162 ............................................................ 35

EIA, What is U.S. electricity generation by energy source, https://www.eia.gov/tools/faqs/faq.cfm?id=427&t=3 (Mar. 2015) ..................... 57

Entergy Comments, EPA-HQ-OAR-213-0602-22874 ................................................... 57

EPA Clean Air Markets Program Data, http://ampd.epa.gov/ampd/ ........................ 83

EPA Memorandum, Best System of Emission Reduction (BSER) for Reconstructed Steam Generating Units and Integrated Gasification Combined Cycle (IGCC) Facilities, EPA-HQ-OAR-2013-0603-0046 .................... 24

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EPA, Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards 3-13 (Dec. 2011), http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf ............................... 46

EPA, Response to Public Comments on Proposed Amendments to National Emission Standards for Hazardous Air Pollutants for Existing Stationary Reciprocating Internal Combustion Engines and New Source Performance Standards for Stationary Internal Combustion Engines, EPA-HQ-OAR-2008-0708-1491 (Jan. 14, 2013)........................................................ 20

ERCOT 2014 State of the Grid Report at 7, http://www.ercot.com/content/news/ presentations/2015/2014%20State_of_the_Grid_Web_21015.pd ......................... 43

EVA Report, http://www.nma.org/ pdf/EVA-Report-Final.pdf ................................ 69

Existing Kansas Wind Farms, http://kansasenergy.org /wind_projects.htm ............. 59

Generation & Transmission Cooperative Fossil Group Comments, EPA-HQ-OAR-2013-0602-23164.......................................................................................... 46

Greenhouse Gas Mitigation Measures Technical Support Document for the Final Rule, EPA-HQ-OAR-2013-0602-36859 ........................................................ 8, 35

Gulf Coast Lignite Coalition Comments, EPA-HQ-OAR-2013-0602-23394.............. 25

http://energyrecoverycouncil.org/wpcontent/uploads/ 2016/02/DMS-3307817-v3-CREA_Minutes-April_9_2015.pdf ......................................................... 61

http://plainswindeis.anl.gov/documents /fpeis/UGP_Wind_BA.pdf (Apr. 2015) ................................................................................................................................. 77

http://www.deq.utah.gov/Pollutants/P/pm/pm25/ ..................................................... 80

http://www.ecomaine.org/education/ NAWTEC%20Maritatopercent20Hewes%20paper.pdf ........................................... 62

http://www.eia.gov/electricity/state/NorthDakota/ ..................................................... 54

http://www.mprnews.org-/story/2010/10/12/ground-level-cities-in-crisis-red-wing ........................................................................................................................... 61

Intermountain Power Agency Comments, EPA-HQ-OAR-2013-0602-24053 ........... 78

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Kansas Department of Health & Environment Comments, EPA-HQ-OAR-2013-0602-23255............................................................................................................. 55

Legal Memorandum Accompanying Clean Power Plan for Certain Issues at 105-10, EPA-HQ-OAR-2013-0602-36872 .................................................................. 51

Legal Memorandum for Proposed Carbon Pollution Emission Guidelines for Existing Electric Utility Units, EPA-HQ-OAR-2013-0602-0419 ...................... 45

LG&E and KU Energy LLC Comments, EPA-HQ-OAR-2013-0602-31932 ....... 24, 61

Luminant Comments, EPA-HQ-OAR-2013-0602-33559 ......... 26, 44, 55, 67, 68, 69, 81

Midcontinent Independent System Operator, Inc. Comments, EPA-HQ-OAR-2013-0602-22547 ..................................................................................................................................... 39, 42

Mississippi Public Service Commission Comments, EPA-HQ-OAR-2013-0602-22931 ...................................................................................................................... 39

Montana Public Service Comm’n Comments, EPA-HQ-OAR-2013-0602-23936 ............................................................................................................................... 39, 54, 69

Nat’l Academy of Sciences, Assessment of Approaches to Updating the Social Cost of Carbon (2016)................................................................................................................ 70

National Rural Electric Cooperative Association Comments , EPA-HQ-OAR-2013-0602-33118 ............................................................................................................................... 45, 46, 47

NERC, Potential Reliability Impacts of EPA’s Proposed Clean Power Plan, Initial Reliability Review, EPA-HQ-OAR-2013-0602-37006 ............................................................................................................................... 39, 42, 46

New Jersey Department of Environmental Protection Comments, EPA-HQ-OAR-2013-0602-22758.......................................................................................... 59

New Jersey Technical Comments, EPA-HQ-OAR-2013-0602-22758 ................... 59, 81

North Dakota Department of Health Comments, EPA-HQ-OAR-2013-0602-24110 ...................................................................................................................... 40

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Oil and Gas Industry Organizations and Participants-II Comments, EPA-HQ-OAR-2013-0602-25423.......................................................................................... 71

Pacific Coast Collaborative Comments, EPA-HQ-OAR-2013-0602-22947 ................ 59

Portland General Electric Comments, EPA-HQ-OAR-2013-0602-23507 (Dec. 1, 2014) .................................................................................................................. 57

Prairie State Generating Company Comments, EPA-HQ-OAR-2013-0602 (Dec. 1, 2014) .................................................................................................................. 27

Public Utility Comm’n of Texas Comments , EPA-HQ-OAR-2013-0602-23305 ..................................................................................................................................... 26, 40

Regulatory Impact Analysis, EPA-HQ-OAR-2013-0602-37105 .................................... 70

Report to N.C. Envtl. Review Comm’n (May 30, 2014), http://daq.state.nc.us/news/ leg/2014_Clean_Smokestacks_Act_Report.pdf. ........................................................ 83

Response to Comments Ch. 3 § 3.2, EPA-HQ-OAR-2013-0602-36876 ...................................................................................................... 32, 33, 49, 62, 72, 73, 80

Robert S. Pindyck, Climate Change Policy: What Do the Models Tell Us?, J. Econ. Lit. 51(3) (2013), http://dspace.mit.edu/openacces-disseminate/1721.1/88036 ............................................................................................ 70

Southern Company Comments, EPA-HQ-OAR-2013-0602-22907 ................. 23, 26, 39

Southwest Power Pool Comments, EPA-HQ-OAR-2013-0602-20757 ....................... 39

Southwest Power Pool, SPP’s Reliability Impact Assessment of the EPA’s Proposed Clean Power Plan (Oct. 8, 2014) ................................................................. 42

Technical Support Document: Resource Adequacy and Reliability Analysis, EPA-HQ-OAR-2013-0602-36847 ................................................................................ 41

Texas Comm’n on Environmental Quality’s Comments , EPA-HQ-OAR-2013-0602-22305 ..................................................................................................................................... 43, 44

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UARG Comments, Supp. No. 12, Social Cost of Carbon TSD, EPA-HQ-OAR-2013-0602-22768 ........................................................................................................................ 23, 24, 25, 70

Utah Comments, EPA-HQ-OAR-2013-0602-23100 ...................................................... 78

Utah’s Energy Landscape, Utah Geological Survey, Circular 117 at 40 (2014), http://energy.utah.gov/wp-content/uploads/Utahs-Energy-Landscape-3rd-Edition.pdf ............................................................................................................................... 79, 80, 81

West Virginia Department of Environmental Protection Comments (Dec. 1, 2014), EPA-HQ-OAR-2013-0602-23540 ..................................................................................................................................... 40, 55

Western Farmers Electric Cooperative Comments, EPA-HQ-OAR-2013-0602-23644 ...................................................................................................................... 47

Wis. Dep’t of Nat. Res. Comments, EPA-HQ-OAR-2013-0602-23541 ................ 72, 73

www.eia.gov/electricity/data/eia923 ................................................................................. 83

www.pacificorp.com/about/co.html ................................................................................. 74

Wyoming Department of Environmental Quality Comments, EPA-HQ-OAR-2013-0602-22977 ..................................................................................................................................... 55, 76

Xcel Energy Inc. Comments, EPA-HQ-OAR-2013-0602-22748 .................................. 59

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GLOSSARY OF TERMS

Act (or CAA) Clean Air Act

BSER Best System of Emission Reduction

CO2 Carbon Dioxide

EIA U.S. Energy Information Administration

EPA U.S. Environmental Protection Agency

ERCs Establishing Tradable Emission Reduction Credits

ERCOT Electric Reliability Council of Texas

JA Joint Appendix

MWh Megawatt-Hour

NERC North American Electric Reliability Corporation

NOx nitrogen oxides

Pounds of CO2 per Megawatt Hour

lbs CO2/MWh

Proposed Rule or Proposal U.S. Environmental Protection Agency, Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, 79 Fed. Reg. 34,830 (June 18, 2014)

RTOs Regional Transmission Organizations

Rule U.S. Environmental Protection Agency, Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, Final Rule, 80 Fed. Reg. 64,662 (Oct. 23, 2015)

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JURISDICTIONAL STATEMENT

Petitioners incorporate by reference the jurisdictional statements included in

Petitioners’ Opening Brief on Core Legal Issues.

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STANDING STATEMENT

Petitioners incorporate by reference the standing statements included in

Petitioners’ Opening Brief on Core Legal Issues.

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STATEMENT OF ISSUES

1. Whether EPA violated section 307 of the Clean Air Act (“CAA” or

“Act”)3 by promulgating a rule it never proposed.

2. Whether the Rule violates section 111 because EPA’s “best system of

emission reduction” is not “adequately demonstrated” and because the Rule’s

emission guidelines are not “achievable” by regulated sources.

3. Whether the Rule arbitrarily and capriciously excludes certain sources of

non-emitting generation from the compliance options available for state plans.

4. Whether EPA failed to consider important aspects of, and has made

critical errors in, its emission guidelines, including:

a. Failing to establish necessary subcategories;

b. Failing to consider renewable energy limits;

c. Regulating sources that can only be regulated under section

111(b); and

d. Conducting a deeply flawed cost-benefit analysis.

5. Whether the Rule is arbitrary and capricious because it fails to

accommodate individual States’ circumstances, thus causing particular harm to

certain States.

3 Unless otherwise stated, all statutory references are to the Clean Air Act.

The Table of Authorities includes parallel citations to the U.S. Code.

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STATUTES AND REGULATIONS

The Rule is codified in 40 C.F.R. Part 60, Subpart UUUU. All applicable

statutes and regulations are contained in the addendum attached hereto or the

addendum to the Opening Brief of Petitioners on Core Legal Issues.

INTRODUCTION

Even if EPA had authority under section 111(d) to fundamentally transform

the electric sector through “generation shifting” and to regulate the activity of owners

and operators of sources rather than the sources themselves,4 the Rule remains fatally

flawed.

The Rule is so untethered to what EPA proposed that no one could have

divined the Rule EPA finalized—an emission reduction program based on separate,

uniform performance rates for coal- and gas-fired units applied nationwide. This

violates a bedrock administrative law principle—that the final rule, or at least

something akin to it, has actually been proposed, so that the public has a meaningful

opportunity to comment.

In part due to this failure, the administrative record does not support EPA’s

conclusions and aggressive emission reduction goals. Nearly everything in the Rule—

from the foundation of EPA’s “best system of emission reduction” to the

4 Petitioners have explained why EPA does not have such authority in

Petitioners’ Opening Brief on Core Legal Issues (“Core Issues Brief”).

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achievability of the emission guidelines,5 from the workability of the individual

“Building Blocks” to EPA’s projections of the renewable and natural gas-fired

generating capacity, from the individual emission limits to EPA’s broadest emission

reduction claims—is based on unfounded assumptions and pure speculation, all made

by an agency that by its own admission lacks expertise to restructure the energy

sector.

This is not how rulemaking works. The Rule must be vacated.

STATEMENT OF THE CASE

I. The Proposed Rule

EPA’s proposed rule would have established emission guidelines in the form of

State-specific annual average carbon dioxide (“CO2”) emission rate goals for each of

the 49 States with existing fossil fuel-fired units. 79 Fed. Reg. 34,830, 34,957, Table 1

(June 18, 2014), JA__, __ (“Proposed Rule” or “the proposal”).6 Each State-specific

goal was designed to reflect the aggregate CO2 emissions performance of all affected

units in that State, adjusted to account for redispatch from coal to gas, EPA’s

5 EPA’s emission “guidelines” are in fact binding standards of performance; to

avoid confusion, however, this brief refers to them as “guidelines.” See Core Issues Brief at 74-78.

6 The Core Issues Brief presents in its Statement of the Case the statutory and regulatory history of section 111; a description of the President’s Climate Action Plan and the Rule; and a summary of the Rule’s requirements. That Statement of the case also provides a detailed explanation of how EPA devised national “CO2 emission performance rates” for fossil fuel-fired power plants based on three “Building Blocks.” To avoid repetition, this brief incorporates by reference that Statement.

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projected generation from qualifying renewable energy sources, and generation

“avoided” through consumer-based energy efficiency measures. Id. at 34,893-94,

JA__-__. EPA based the Proposed Rule’s emission guidelines on a “best system of

emission reduction” (“BSER”) comprising four EPA-identified “Building Blocks.” Id.

at 34,836-37, JA__-__.

Building Block 1 was based on heat rate improvements (i.e., improved

combustion efficiency) of 6% at coal units across each State’s fleet. Id. at 34,859-61,

JA__-__.

Building Block 2 was based on displacing some or all of a State’s coal-fired

generation with increased generation from existing natural gas combined cycle units,

until those gas units operate at 70% of their annual nameplate capacity on average or

until coal generation is eliminated from the State. Id. at 34,862-64, JA__-__. EPA

observed that 10% of existing gas units in the nation operated at annual capacity

factors (i.e., the ratio of a unit’s actual output to its maximum potential output over a

year) of 70% or higher in 2012 and assumed the remaining fleet could reach and

sustain the same utilization level on average. Id. at 34,863, JA__.

Building Block 3 reflected new renewable generation and generation from

under-construction and nuclear capacity at risk for retirement. Id. at 34,866, JA__.

Finally, Building Block 4 was based on reducing consumers’ electricity demand

through State-run energy efficiency programs. Id. at 34,871, JA__.

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EPA calculated each State’s unique goal by adjusting 2012 generation and

emissions data from the State’s regulated units to reflect the theoretical application of

each Building Block on a statewide level. Id. at 34,895-96, JA__-__. The resulting

emission guidelines were binding only on States and were not targeted at—or directly

applicable to—individual units. Instead, EPA expected States to develop their own

plans to impose legal requirements on a broad class of “affected entities.” Id. at

34,901, JA__. For example, state plans might oblige entities other than existing fossil-

fuel units to develop new renewable generation or implement consumer efficiency

programs. Id. The Proposed Rule also allowed States to adopt “market-based trading

programs” and develop multi-State plans, but trading was not an integral part of the

BSER. See id. at 34,837, JA__.

II. The Rule

Although the Rule repeats many of the proposal’s fundamental legal defects,7

its core regulatory requirements bear little resemblance to the proposal. In particular,

EPA dramatically altered the most fundamental aspect of the emission guidelines,

based its definition of BSER and the target implementation levels on an entirely new

rate-based methodology, and included emissions trading as an integral part of the

Rule. Each of these changes is discussed below.

7 See Core Issues Brief at 29-86.

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A. Nationally Uniform Performance Rates

In stark contrast to the proposal, the final Rule establishes two nationally

uniform emission rates–(i) one for coal-, oil, and gas-fired steam generating units;8 and

(ii) one for natural gas combined cycle units. 40 C.F.R. part 60, subpart UUUU, Table

1. These rates, and state plans implementing them, only apply to coal and gas units,

and not to the broad range of “affected entities” as proposed.

Although the Rule also specifies rate-based and mass-based goals for each

State, these are simply alternative expressions of the uniform performance rates. The

Rule makes clear the emission rates are the “chief regulatory requirement of th[e]

rulemaking,” 80 Fed. Reg. at 64,820, 64,823, JA__, __; the State goals, derived from

the performance rates, are alternative ways to demonstrate compliance. Id. at 64,820,

JA__. EPA based the national performance rates on modified versions of three of the

four proposed “Building Blocks,” applied regionally rather than on the State level. Id.

at 64,718, JA__.

EPA’s adoption of nationally uniform rates that apply only to affected units

shifts the burden of assuring that alternative generation would be available away from

the States (as in the Proposed Rule) to the owners and operators of affected units.

Instead of expecting States to ensure compliance with statewide goals through a broad

8 The vast majority of steam units are coal units. References in this brief to coal

units include the small number of gas- and oil-fired steam units the Rule covers. “Gas units” refers to natural gas combined cycle units.

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range of state measures, the Rule effectively imposes on owners and operators of

affected units the obligation to do whatever is necessary to comply with the rates,

including investing in and shifting generation to alternative sources of generation,

subsidizing alternative generation, or shutting down affected units. Id. at 64,718,

64,724, JA__, __.

B. BSER Determination and Building Block Targets

As the basis for the national performance rates, EPA determined the BSER

would be based on the modified three Building Blocks. Id. at 64,744, JA__. Rather

than applying the BSER on a State-by-State basis, as proposed, EPA applied the

Building Blocks in the aggregate across three broad regions, such that the final Rule’s

performance rates are not based on measures that can be implemented within many

States or reflect achievable targets for individual units. Id. at 64,813, 64,816-19, JA__,

__-__.

This shift from State-specific goals based on State-by-State analysis to uniform

performance rates based on a regional analysis led EPA to find that each Building

Block could “achieve” new, and in most cases more aggressive, generation targets. For

example, in estimating heat rate improvement targets for coal units under Building

Block 1, the Agency disavowed any reliance on “implementation of specific

measures.” Greenhouse Gas Mitigation Measures Technical Support Document for

the Final Rule (“GHG Mitigation Measures TSD”) at 2-25, EPA-HQ-OAR-2013-

0602-36859, JA__. Instead, EPA assumed that units could “maintain [over time] the

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better heat rates they have previously achieved” only over a brief period by reducing

variation from those heat rates using “good maintenance and operating practices.” Id.

Based on past heat rate data, EPA estimated potential heat rate improvements of 2.1

to 4.3% for the three regions. 80 Fed. Reg. at 64,789, 64,817, JA__, __.

For Building Block 2, EPA altered the target utilization rate for gas units from

70% of net nameplate capacity, to 75% of net summer capacity. Id. at 64,795, JA__.

The final Rule also expects that under-construction gas units, once completed, can

contribute 20% of capacity to displace coal-fired generation. See id. at 64,817, JA__.

EPA modified Building Block 3 by removing nuclear and existing renewable

generation from the BSER and dramatically increasing the incremental renewable

generation targets it considers achievable. Id. at 64,803, 64,809, JA__, __. Instead of

basing state renewable generation targets on the average of neighboring state policies,

EPA determined the nationwide maximum year-to-year change in renewable

generation from 2010-2014 and added that amount each year after 2023—in addition

to aggressive projections of “base case” renewable growth—to develop regional

renewable generation targets, more than doubling the amount of new renewable

energy predicted under the Proposed Rule. Id. at 64,807-08, JA__-__.

Moreover, EPA explained that it assessed whether the BSER was adequately

demonstrated, and whether the Building Block targets and the emission guidelines

were achievable, on an industry-wide basis rather than for individual affected units. See

id. at 64,816-19, 64,779, JA__-__, __; CO2 Emission Performance Rate and Goal

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Computation Technical Support Document for CPP Final Rule (“Goal Computation

TSD”) at 6, EPA-HQ-OAR-2013-0602-3850, JA__. Further, EPA clarified its BSER

is not simply based on reducing the operations of fossil units. Instead, fossil

generation is being reduced due to a shift to alternative generation, including

substantially increased renewable generating capacity that EPA claims will assure that

overall demand is met. See 80 Fed. Reg. at 64,724 n.352, 64,782, JA__, __. As such,

EPA’s conclusion that its BSER is adequately demonstrated (and that its emission

guidelines are achievable) relies on finding that the resulting generation mix can fully

meet demand that was previously served by fossil fuel-fired generation.

C. The Integral Role of Trading Programs

Unlike the proposal, the Rule makes emissions trading programs “an integral

part of [EPA’s] BSER analysis,” establishing tradable emission reduction credits

(“ERCs”) as the only mechanism available for affected units to achieve the Rule’s

uniform emission performance rates. Id. at 64,734, JA ___.9 In other words, EPA’s

assumption that States will “establish standards of performance incorporating

emissions trading” is key to its conclusion that the owners and operators of all

affected units have tools available to implement the BSER. Id. at 64,735, JA__.

Likewise, EPA’s decision to apply BSER on a regional rather than state level assumes

9 This is underscored by EPA’s proposed federal plan, which requires interstate

trading to achieve its standards. 80 Fed. Reg. at 64,966-65,011, (Oct. 23, 2015).

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the availability not only of trading, but interstate trading, because an affected unit’s

standard will be based at least partly on emission-reducing opportunities outside its

State. Id. at 64,666, 64,673, 64,827, JA__, __, __.

The only way an affected unit can comply with the Rule’s uniform emission

performance rates is to generate, purchase, or hold a sufficient number of ERCs

through a trading program to calculate a lower (wholly fictional) average emission rate

for the source at or below 1,305 pounds of CO2 per megawatt hour (“lbs

CO2/MWh”) (for coal units) or 771 lbs CO2/MWh (for gas units). 40 C.F.R. §

60.5790(c)(1); see also 80 Fed. Reg. at 64,752, JA__ (listing actions affected units can

take to achieve limits, all of which include using ERCs). These ERCs are not

automatically issued or distributed to affected units. They must be created through the

production of qualifying generation, such as new renewable generation, and then

transferred. Increased generation from gas units may also create ERCs that can be

used for compliance by coal units. 80 Fed. Reg. at 64,905 , JA__. Because increased

generation from existing gas units must itself be covered by ERCs from other

qualifying sources, the Rule relies doubly on ERCs generated from increased

renewable generation. Id. at 64,905, JA__. Moreover, ERCs can only exist if they are

provided for in a State’s plan, and they can only be traded between States if expressly

allowed in the plans of both the generating and purchasing States.

Therefore, the Rule’s requirements cannot be met if EPA’s projected levels of

renewables or a sufficiently robust trading program fail to materialize. Any shortfall in

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renewable generation will yield a shortfall in ERCs, making it impossible for affected

units to obtain the only available compliance tools to generate electricity.

SUMMARY OF ARGUMENT

The final Rule is fatally flawed on myriad procedural and substantive grounds.

It was promulgated in a manner flatly at odds with the protections expressly set out in

the Act, and its substance is spawned of pure speculation, unsupported by the record.

The Rule must be vacated because it is arbitrary, capricious, and contrary to law.

I. Meaningful public participation is an essential element of rulemaking. EPA’s

Rule could not have been divined from its proposal. By departing so radically from

that proposal, EPA promulgated a Rule on which the public had no opportunity to

comment.

II. EPA bears the burden to show that its selected “best system of emission

reduction” has been adequately demonstrated to be reliable, efficient, and not

exorbitantly costly. EPA must also show the emission guidelines derived from that

system are “achievable” by individual sources, operating in the real world. Conjecture,

speculation, and crystal ball inquiries do not suffice.

Here, because EPA uses a restructuring of the energy supply sector to drive

CO2 emission reductions, EPA must show that its system actually can achieve that

result, without impairing the reliability of the nation’s electric supply. EPA has not

made that showing for its three “Building Blocks,” separately or together.

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EPA must also show that individual sources can achieve the emission

guidelines, consistent with meeting electric demand. EPA concedes that no individual

source could install controls that would enable it to meet the guidelines. Instead, the

guidelines can only be met if a substantial number of sources shut down and the

remaining sources purchase ERCs from EPA-favored generation facilities. That

cannot happen without threatening electric supply reliability in many States.

III. The Rule treats the electric sector as a single “grid” comprising all

generating sources in the nation. But in selecting which sources can generate emission

reduction credits or be counted for compliance purposes, EPA arbitrarily

discriminates against many existing, low- or zero-emission generating units that are

part of that grid.

IV. Though EPA purports to have taken State-specific circumstances into

account in setting the 47 individual state emission goals, in fact it only considered how

much coal generation and how much gas generation each State possessed. EPA gave

no meaningful consideration to State-specific factors that will make compliance with

its emission guidelines impossible, including imminent plant retirements, transmission

and pipeline infrastructure, the difficulty of trading between States and Indian tribes,

State-specific electric market structure and reliability challenges, historic emission rates

that show that EPA’s emission guidelines are unrealistic, and earlier voluntary

emission reduction efforts that make the Rule’s additional required reductions

impossible to achieve.

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ARGUMENT

I. EPA Violated Section 307 By Promulgating A Never-Proposed Rule.

In the Rule, EPA departed fundamentally from the proposal, turning the

rulemaking process into a mockery. “The process of notice and comment rule-making

is not to be an empty charade,” but instead “a process of reasoned decision-making”

in which “interested parties” are afforded “the opportunity . . . to participate in a

meaningful way.” Conn. Light & Power Co. v. NRC, 673 F.2d 525, 528 (D.C. Cir. 1982).

Meaningful participation is impossible when EPA proposes one thing and finalizes

something else entirely.

A. The Rule Is Fundamentally Different From The Proposal.

As explained above, the final Rule establishes a CO2 emission reduction

program based on uniform, nationally applicable performance rates for two types of

units – 1,305 lbs CO2/MWh for coal, and 771 lbs CO2/MWh for gas. 80 Fed. Reg. at

64,752, JA__. Every other element of the Rule flows from these two performance

rates. Yet neither rate, nor even the concept of such a rate, was noticed in the

Proposed Rule. In fact, EPA clearly stated that it had rejected the option of setting

uniform rates, emphasizing it was proposing “the use of output-weighted-average

emission rates for all affected [units] in a state rather than nationally uniform emission rates

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for all affected [units] of particular types.” 79 Fed. Reg. at 34,894, JA__ (emphasis added).10

The Rule thus does exactly what EPA said in its proposal it would not do.

EPA had proposed to develop a unique goal for each State based on a complex

mathematical formula. Id. at 34,896 n.265, JA__. That goal was to be a single, blended

rate that applied to both the coal- and gas-fired units in a State. Id. at 34,895, JA __. A

broad range of “affected entities,” including producers of alternative generation, were

responsible for implementation of these state goals. Everything was tied to EPA’s

establishment of these State-specific, blended, output-weighted-average emission

rates. EPA thus did not include, or solicit any comment on, any emission reduction

program based on uniform unit-specific performance rates applicable to general

categories of units. Nor did EPA signal that it was considering adopting a rule that

would shift all responsibility for implementation from “affected entities” to

“owners/operators” of affected units.11

Finally, EPA adopted applicability language in the Rule that expanded coverage

to units not subject to the proposal. Under the proposal, only facilities “constructed

10 The only other reference to “uniform” rates in the proposal is later on the

same page, where EPA explains why it is proposing the use of output-weighted-average emission rates rather than nationally uniform rates. 79 Fed. Reg. at 34,894, JA__.

11 This case thus stands in stark contrast to the typical case where EPA proposes to set a standard at a particular level, but also takes comment on other possible levels. See, e.g., 79 Fed. Reg. 1,430, 1,470, 1,487 (Jan. 8, 2014) (soliciting comment on a range of possible new unit standards for the same pollutant and source category regulated here).

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for the purpose of” supplying to the grid 1/3 or more of potential output and 219,000

MWh net-electric output were covered. 79 Fed. Reg. at 34,954, JA__. This mirrored

decades-old applicability language governing steam generating units under the NSPS,

Subpart Da. See 40 C.F.R. §§ 60.40Da(a)(1), 60.41Da; see also 44 Fed. Reg. 33,580,

33,613 (June 11, 1979). The final Rule expands coverage to include most generators

connected to a utility power distribution system and capable of selling more than 25

MW of electricity. 40 C.F.R. § 60.5845.

Simply put, EPA promulgated a final rule it never proposed.

B. EPA’s Circumvention of the Rulemaking Process Requires Vacatur.

By finalizing a Rule bearing no resemblance to the proposal, EPA violated its

obligations under section 307(d)(3) and circumvented the rulemaking process. By law,

EPA must provide in each proposal the factual data on which that proposed rule is

based, the methodology used in obtaining and analyzing the data, and major legal

interpretations and policy considerations underlying the proposal. CAA §

307(d)(3)(A)-(C). The very purpose of this requirement is to give the public a

meaningful opportunity to comment. Here, EPA pulled the ultimate “surprise

switcheroo,” Envtl. Integrity Project v. EPA, 425 F.3d 992, 996 (D.C. Cir. 2005),

rendering any comment opportunity illusory.

This is not a “logical outgrowth” case, in which EPA promulgated a rule “that

differs in some particulars from its proposed rule.” Small Refiner Lead Phase-Down Task

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Force v. EPA, 705 F.2d 506, 546 (D.C. Cir. 1983). “Whatever a ‘logical outgrowth’ of

[an agency’s] proposal may include, it certainly does not include the Agency’s decision

to repudiate its proposed [position] and adopt its inverse.” Envtl. Integrity Project, 425

F.3d at 998. For such changes to be lawful, the “necessary predicate” is that the

agency “has alerted interested parties to the possibility of the agency’s adopting a rule

different than the one proposed,” so the final rule is a “logical outgrowth” of the

proposal. Kooritzky v. Reich, 17 F.3d 1509, 1513 (D.C. Cir. 1994).

This doctrine does not extend to a final rule that finds no roots in, and actually

adopts the very frame work expressly rejected in, the agency’s proposal. “Something is

not a logical outgrowth of nothing,” and the doctrine is inapplicable where

commenters would have had to “divine [the agency’s] unspoken thoughts.” Envtl.

Integrity Project, 425 F.3d at 996 (citations omitted). Agencies “may not turn the

provision of notice into a bureaucratic game of hide and seek.” MCI Telecomms. Corp. v.

FCC, 57 F.3d 1136, 1142 (D.C. Cir. 1995).

No one could have divined from EPA’s proposal that a final rule based on

uniform, nationally-applicable performance rates was even a possibility, that units not

even addressed in the proposal would be regulated, or that EPA would apply an

entirely different methodology with new data in establishing those rates. Such silence

in a proposal does more than frustrate meaningful comment; it assures no comment.

EPA should have proposed and taken comment on its new approach, just as

EPA did when it took a fundamentally different approach in the CO2 standards for

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new generating units that were promulgated on the same day.12 That EPA did not take

the same easy (and lawful) step here bespeaks the Administration’s rush to get the

Rule out the door. Unless this Court repudiates EPA’s conduct, it invites abuse of the

rulemaking process. The Rule must be vacated. If EPA wishes to promulgate this

Rule, it must start over, with a proper proposal.

II. EPA’S BSER Is Not “Adequately Demonstrated” And Its Emission Guidelines Are Not “Achievable” Under Section 111.

A. EPA Must Show Both “Adequate Demonstration” Of The BSER And “Achievability” Of The Emission Guidelines.

This Court “ha[s] established a rigorous standard of review under section 111.”

Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 429 (D.C. Cir. 1980). EPA must establish that

the BSER is “‘adequately demonstrated,’” and that the performance standards derived

from the BSER are “‘achievable.’” Id. (quoting CAA § 111(a)). EPA fails to establish

either. Both requirements derive from section 111(a)(1), which defines a “standard of

performance” as

a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction) the Administrator determines has been adequately demonstrated.

12 EPA first proposed those standards for new generating units on April 13,

2012. 77 Fed. Reg. 22,392. After “receiv[ing] more than 2.5 million comments,” along with “new information,” EPA formally withdrew that proposal on January 8, 2014, 79 Fed. Reg. 1,352, and initiated a new rulemaking process, 79 Fed. Reg. 1,430.

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CAA § 111(a)(1). The two, though interrelated, are legally distinct, and the Rule must

satisfy both.

The first demands that EPA “adequately demonstrate[]” that the technology

selected as BSER “is one which has been shown to be reasonably reliable, reasonably

efficient, and [not] exorbitantly costly in an economic or environmental way.” Essex

Chem. Corp. v. Ruckelhaus, 486 F.2d 427, 433 (D.C. Cir. 1973). Although EPA does not

have to show the technology is currently in regular use, it must “‘adequately

demonstrate[]’ that there will be ‘available technology.’” Portland Cement Ass’n v.

Ruckelhaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citation omitted).

The second requires EPA to establish the performance rate to be achieved

through application of the BSER is “within the realm of the adequately demonstrated

system’s efficiency.” Essex Chem. Corp., 486 F.2d at 433-34. EPA may not set a rate “at

a level that is purely theoretical or experimental,” nor may it base its assessment of

feasibility on “its subjective understanding of the problem or a ‘crystal ball inquiry.’”

Id. at 433-34 (quoting Portland Cement, 486 F.2d at 391); accord Lignite Energy Council v.

EPA, 198 F.3d 930, 934 (D.C. Cir. 1999) (“EPA may not base its determination … on

mere speculation or conjecture”). Rather, EPA must “affirmatively show that its

standard reflects consideration of the range of relevant variables that may affect

emissions in different plants” and must explain how the standard is “capable of being

met under most adverse circumstances which can reasonably be expected to recur.”

Nat’l Lime Ass’n, 627 F.2d at 431 n.46, 433.

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B. EPA Failed To Satisfy Its Burdens.

Until this Rule, EPA has always used tests and studies of existing control

equipment to determine whether individual sources could apply a particular

technology (e.g., a wet scrubber) or operational practice (e.g., fuel switching) to reduce

emissions to a specified level. See, e.g., id., at 627 F.2d at 424-25 (baghouses, scrubbers,

and other technologies); Essex Chem. Corp., 486 F.2d at 435-46 (SO2 absorption

systems, acid-mist eliminators, and other technologies). The Court would review to

ascertain whether EPA had shown both that (1) the technology or practice (the

“system of emission reduction”) was “adequately demonstrated” and (2) the resulting

emission limit was “achievable” on a source-by-source basis. E.g., Sierra Club v. Costle,

657 F.2d 298 (D.C. Cir. 1981); Nat’l Lime Ass’n, 627 F.2d at 431-48; Essex Chem. Corp.,

486 F.2d at 436-41.

Here, EPA’s “system of emission reduction” is neither a technology nor an

operational process that controls emissions from individual facilities. Instead, it is a

“system of alternative electric generation” intended to reduce emissions from the

whole industry, primarily by shifting generation from existing coal units to gas units

and new renewable resources.

By de-coupling BSER from actions taken at individual sources, and instead

reorganizing the industry, EPA does not escape its burden to show the system has

been adequately demonstrated and the emission guidelines are achievable. To the

contrary, it must now evaluate not just whether individual sources will be able to

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reach a certain emission target upon installing a tested technology, but whether the

lights will stay on across the country under the Rule. This is critical, because if EPA

has guessed wrong, brown-outs, black outs, and severe economic disruption will

result.

This Court therefore must “take a ‘hard look’” at EPA’s facts and reasoning,

Small Refiner Lead Phase-Down Task Force, 705 F.2d at 520 (citation omitted), and it

should not afford any deference to EPA’s explanations, as the agency admittedly lacks

expertise in the power supply industry. Unbelievable, Inc. v. N.L.R.B., 118 F.3d 795, 805

(D.C. Cir. 1997) (citation omitted) (the “court does not defer to agency decision in

matter outside of agency’s expertise”).13

EPA bears an enormous burden. It must show its system of alternative

generation will be “reasonably reliable,” “reasonably efficient,” and not “exorbitantly

costly.” Essex Chem., 486 F.2d at 433. EPA must show its plan will work. This involves

complex considerations about how electricity will be generated and distributed,

including whether each Building Block can be employed at EPA’s assumed levels,

where new generating resources will be located, whether sufficient transmission

13 EPA, Response to Public Comments on Proposed Amendments to National

Emission Standards for Hazardous Air Pollutants for Existing Stationary Reciprocating Internal Combustion Engines and New Source Performance Standards for Stationary Internal Combustion Engines at 50, EPA-HQ-OAR-2008-0708-1491 (“The issues related [to] management of energy markets and competition between various forms of electric generation are far afield from EPA’s responsibilities for setting standards under the CAA.”).

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infrastructure will exist to handle the generation shifting the Rule requires, and

whether the resulting mix of generating assets can provide reliable power at all times

to all customers in all parts of the nation. EPA is required to identify a BSER “that

has been demonstrated” to avoid precisely this kind of guesswork.

Because EPA’s BSER is not tethered to actions taken at individual sources,

even if EPA had adequately demonstrated its system of alternative generation on a

sector wide-basis (which it did not), it still would not follow that EPA’s emission

guidelines are achievable. EPA must independently show that individual existing

sources and States can employ the Building Blocks to achieve the emission guidelines

on a consistent basis, accounting for “the range of relevant variables that may affect

emissions in different plants.” Nat’l Lime Ass’n, 627 F.2d at 431 n.46, 433. In so doing,

EPA may not resort to “mere speculation or conjecture.” Lignite Energy Council, 198

F.3d at 934. But EPA cannot avoid such speculation, as reorganizing an entire

industry to reduce emissions has never before been attempted, much less

demonstrated.

EPA has not carried its burden here. It has not shown the three Building

Blocks are adequately demonstrated or achievable. It has failed to reasonably assess

the substantial new transmission the Rule effectively requires. It has not shown

individual sources can achieve its performance rates through application of the BSER.

And it illegally requires sources and States to rely on an inadequately demonstrated

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emissions trading program to achieve compliance with its emission guidelines and

State plan requirements.

1. EPA Has Not Shown That Any Of Its Three Building Blocks Is Adequately Demonstrated Or Achievable.

As explained below, EPA sought to demonstrate its Building Blocks on a

regional basis. By so doing, it failed to comply with the statutory requirement to

demonstrate that its BSER is adequately demonstrated and its emission guidelines are

achievable by sources. See National Lime Ass’n, 627 F.2d at 434. But even assuming a

regional approach is lawful, EPA also failed to demonstrate that the Building Blocks

targets are achievable regionally.

a. Building Block 1.

EPA’s first Building Block relies on heat rate improvements to reduce CO2

emissions at existing coal-fired units. 80 Fed. Reg. at 64,745, JA__. But EPA’s heat

rate improvement target is based on abstract, arbitrary calculations untied to any

specific heat rate improvement measures. See id.; GHG Mitigation Measures TSD at 2-

25, JA__. Consequently, EPA has failed to establish that any specific measures are

adequately demonstrated, or that its Building Block 1 target is achievable.

EPA calculated the average heat rate improvement that would occur if each

coal-fired unit could reduce its hourly heat rate by a percentage value (or “consistency

factor”) based on the lowest historical “benchmark” values reported under similar

operating conditions. GHG Mitigation Measures TSD at 2-45 to 2-47, JA__-__. Using

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this approach, EPA estimated heat rate improvement targets for each region. Id. at 2-

50, JA__.14 Essentially, EPA observed that units’ heat rates appeared to be lower at

some times or in some years than others, and then assumed that coal units could

proactively and continually replicate past optimum heat rate observations simply by

using “good maintenance and operating practices.” Id. at 2-25, 2-45, JA__, __.

Nothing in the record supports this assumption. In fact, the opposite is true:

although some units might be able to take steps to marginally improve or maintain

their heat rates, heat rate variation is driven by factors beyond their control. UARG

Comments at 221, EPA-HQ-OAR-2013-0602-22768, JA__; Southern Company

Comments at 81, 91-96, EPA-HQ-OAR-2013-0602-22907, JA__. Yet EPA did not

distinguish between variations that are driven by controllable factors and those that

are uncontrollable for an existing source, such as unit design, size, cooling conditions,

and location. 80 Fed. Reg. at 64,788, JA__; see also UARG Comments at 221, JA__.15

14 EPA claimed two other approaches supported these targets: (i) a calculation

of the average improvement if each unit returned to its best two-year average heat rate; and (ii) a similar approach using separate estimates of the best two-year average heat rate under different operating conditions. 80 Fed. Reg. at 64,788-89, JA__-__.

15 The same logic holds true for numerous other sources for myriad reasons. The Rule did not consider, nor did EPA allow comment on, issues of critical importance to many sources, and space constraints do not permit them to be raised with specificity here. This Court must understand that not raising those issues does not diminish their importance; deficiencies in the Rule were interwoven into the warp and woof of every sentence, requirement, and the very logic underlying the Rule.

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For instance, although EPA claims that it controlled for the influence of

capacity factor and ambient temperature, two primary drivers of heat rate, units have

no way to control their capacity factors, which are driven by demand and each unit’s

position in the dispatch or local meteorological conditions. 80 Fed. Reg. at 64,788,

JA__. Units operate more efficiently at higher loads and on cooler days. Id.; see also

GHG Mitigation TSD at 3-5, JA__ (capacity factor accounts for up to a 50% variation

in heat rate); UARG Comments at 209-10, JA__-__; LG&E and KU Energy LLC

Comments at 13-14, EPA-HQ-OAR-2013-0602-31932, JA__-__; EPA

Memorandum, Best System of Emission Reduction (BSER) for Reconstructed Steam

Generating Units and Integrated Gasification Combined Cycle (IGCC) Facilities

(“Reconstructed EGU TSD”) at 4, EPA-HQ-OAR-2013-0603-0046, JA__ (operating

at 50% load can increase heat rate by 10% or more). EPA did not truly “control for

the influence of [the] variables” as it claims. 80 Fed. Reg. at 64,788, JA__. Its

approach is premised on average operating conditions over the historical period EPA

analyzed; it cannot account for changed operating conditions the coal-fired fleet can

be expected to face in the future.

Consequently, if the coal fleet faces lower capacity factors (which is the express

goal of Building Block 2’s shift to gas generation) or higher ambient temperatures

(which is likely if Building Block 2 forces more coal units to serve as summertime

peak load units), the resulting increase in heat rate could overwhelm any of the fleet’s

marginal heat rate improvements. By failing to account for uncontrollable factors that

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can counteract heat rate improvement efforts, EPA ignored its duties to ensure that

its BSER “is reasonably reliable” and to set performance rates that are “achievable

under the range of relevant conditions.” Nat’l Lime Ass’n, 627 F.2d at 431 n.46, 433.

More fundamentally, EPA failed to show that sufficient heat rate-improving

measures are available for units to implement to achieve EPA’s targets. EPA admits

its targets are based on statistical analyses and not on “heat rate improvements that

would be achieved by implementation of specific measures.” GHG Mitigation

Measures TSD at 2-25, JA__. EPA provides a list of “best operating practices” and

“equipment upgrades” that are conceptually capable of reducing heat rates, id. at 2-11,

JA__, but fails to analyze whether those measures can yield sufficient improvements,

whether they are available to a sufficient number of units, or whether they are already

being implemented at units and thus cannot be further deployed. In other words,

EPA has no idea whether Building Block 1 will work on the ground.

In reality, the heat rate improvement measures EPA lists—particularly the

lower-cost “best operating practices”—are already widely adopted. 80 Fed. Reg. at

64,792, JA__. Many units, having already made such improvements, cannot achieve a

reduction in heat rates from 2012 levels, especially because many of the units made

modifications to comply with EPA rules that require additional energy to operate and

therefore reduce the efficiency of the unit. See UARG Comments at 211-28, JA__-__;

Gulf Coast Lignite Coalition Comments at 25-27, EPA-HQ-OAR-2013-0602-23394,

JA__-__; Southern Company Comments at 80-91, EPA-HQ-OAR-2013-0602-22907,

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JA__-__; LG&E and KU Energy LLC Comments at 10-14, JA__-__; Luminant

Comments at 53-59, EPA-HQ-OAR-2013-0602-33559, JA__-__. Particularly in

energy-deregulated markets such as the Electric Reliability Council of Texas

(“ERCOT”), coal generators have installed state-of-the-art technologies to improve

thermal efficiencies simply to compete effectively, and there are few additional gains

available. See Public Utility Comm’n of Texas Comments (“PUCT Comments”) at 42,

EPA-HQ-OAR-2013-0602-23305, JA__. Also, the actual payoffs of EPA-identified

measures are limited, given that they are not compatible with all units, and their

benefits are non-additive and degrade over time. UARG Comments at 212-16, JA__-

__; Luminant Comments at 55, 57 n.237, JA__, __.

EPA failed to assess whether any specific measures are available for units to

achieve its Building Block 1 targets, and did not show that the targeted heat rates have

ever been maintained across the coal fleet. There is no basis for assuming that the best

historical efficiency ever achieved can be achieved every year in the future.

Because many of EPA’s erroneous assumptions were never noticed, supra

Section I, there was no opportunity to comment on them. By not allowing comment,

for example, on incorrect 2012 data, EPA is severely penalizing new units

intentionally designed to be highly efficient and provide base load electricity for a 30-

year life span. Such a procedurally deficient Rule, with a BSER that fails to meet

statutory standards, is arbitrary, capricious, and contrary to law. Prairie State

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Generating Company Comments at 3, 6, EPA-HQ-OAR-2013-0602 (Dec. 1, 2014),

JA __, __.

b. Building Block 2.

EPA’s second Building Block also is not adequately demonstrated and its

targets are not achievable, because EPA (i) failed to support its target for increased

utilization of existing gas units, (ii) erroneously counted hypothetical “unused”

capacity from under-construction gas units, and (iii) improperly relied on capacity

from gas units’ duct burners for redispatch.

(i) EPA Failed To Support Its Target For Increased Utilization Of Existing Gas Units.

Building Block 2 assumes existing fossil steam generation will shift “to existing

[gas units] within each region up to a maximum [gas] utilization of 75% on a net

summer basis.” 80 Fed. Reg. at 64,795, JA__. EPA bases this 75% capacity factor on

speculative assumptions about the level of generation the existing gas fleet can

achieve, without assessing the fleet’s real-world constraints, accounting for the

eventual deterioration and retirement of existing units, or reconciling its assumptions

with its modeling results. See GHG Mitigation Measures TSD at 3-5 to 3-13, JA__-__.

Thus, EPA has not shown that the existing gas fleet can obtain an overall 75%

capacity factor, or that its Building Block 2 target is achievable.

EPA relied on three data types to justify its 75% capacity factor; none of these

supports its conclusion.

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First, EPA cited a statistical analysis based on 2012 generation. Id. at 3-6 to 3-

11, JA__-__. This reveals the overall average capacity factor of the gas fleet in 2012

was only 46%; more than 20% of the fleet operated at a capacity factor of less than

20%, and only 15% operated at or above the 75% level. Id. at 3-6, 3-9, JA__, __.

These data—which occurred in a year with historically low natural gas prices that

already incentivized the use of gas generation, see id. at 3-11, JA__—hardly support a

conclusion that a fleet-wide capacity factor of 75% has been demonstrated or is

achievable.

In fact, the existing fleet would have to increase its generation by about two-

thirds from 2012 levels to meet the 75% capacity factor, and EPA provides no data or

analysis suggesting how that level of generation might be accomplished. EPA argues

nonetheless that because capacity factors of 75% or more were achieved in each of

the electricity interconnections on at least one day, this “demonstrate[s] the ability of the

natural gas transmission system to support this level of generation.” GHG Mitigation

Measures TSD at 3-11, JA__. But EPA never explains how these high usage numbers

establish that such circumstances could be achieved across the fleet day-after-day, year-

after-year, and never considers the various site- or region-specific factors such as

economics, regional grid restrictions, and regulatory constraints that would inform

that question.

Second, EPA presented data suggesting natural gas generation is expected to

grow over time. Id. at 3-11 to 3-13, JA__-__. This is irrelevant. Such growth will come

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to a significant extent from the construction of new units. But since new units cannot

be used to “average down” the CO2 emission rates for affected fossil-steam units, 80

Fed. Reg. at 64,801, JA__, EPA’s data provides no indication that the capacity factor

for the existing fleet can increase by the approximately two-thirds EPA assumes.

Third, EPA pointed to the availability of the existing gas fleet, stating that

“EPA assumes that [gas] has an availability of 87%” and that certain units may have

availability factors as high as 92%. GHG Mitigation Measures TSD at 3-5, JA__. But

“availability” (the percentage of hours during a given year a unit is available to not

offline due to outages) offers no information about whether those units are capable of

operating at sufficiently higher capacity factors over an extended period to meet a

fleet-wide capacity factor target of 75%, or are located sufficiently close to coal units

to supply the load that the displaced generation would have served. For example,

many units with “available” capacity cannot increase utilization due to permit limits

on operations, the need to provide dedicated backup capacity for renewable resources,

or their location in areas designated as nonattainment for one or more ambient air

quality standards. See UARG Comments at 230-31, JA__.

EPA never assessed these critical questions. Even if the fleet could physically

achieve such a high capacity factor, Building Block 2 can work only if the fleet is

located in areas where it can serve demand that would otherwise be supplied by coal

generation. For example, it is of little use if a gas unit in Florida can physically operate

at a 75% capacity factor if the coal generation it needs to displace is located in North

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Dakota, even though both locations are within the eastern interconnection. That is

not how electricity transmission works.

These limitations are heightened in Texas, where over 90% of electricity is

consumed in ERCOT, which has limited import capacity. See infra II.B.2.b.i. In

calculating the amount of generation shifting under Building Block 2, EPA did not

consider this but instead assumed, wrongly, that generation shifting can occur freely

across entire interconnections. Goal Computation TSD at 14-15, JA__-__.

Finally, EPA’s Building Block 2 assumption is undermined by its own

modeling. EPA used its Integrated Planning Model to show that existing gas units

could be operated at a 75% capacity factor. Id. at 3-20, JA__. What the model actually

showed was that, to achieve that capacity factor, existing gas units would have to

displace generation not only from existing coal units, as contemplated under Building

Block 2, but also from new gas units in significant amounts. Compare CPP Base Case

Modeling, Base Case RPT Files, RegionalSummaryModelRegionSets, sheet at rows

2335 and 2355, JA__, with CPP BB2 75% Modeling, BB2-75% RPT Files,

RegionalSummaryModelRegionSets, rows 2335 and 2355, JA__. EPA’s model thus

demonstrates that the existing gas cannot achieve a 75% capacity factor through

generation shifting from coal units.

EPA failed to meet its burden with respect to Building Block 2.

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(ii) EPA Erroneously Counted “Unused” Capacity From Under-Construction Units.

EPA also erred by counting hypothetical “unused” generating capacity from

under-construction gas units as available for redispatch under Building Block 2. EPA

assumed gas units that were under-construction or commenced operation in 2012

would operate at a 55% annual capacity factor in the future without the Rule, leaving

20% of their generating capacity available to displace generation from coal units. 80

Fed. Reg. at 64,817, JA__.

This assumption is speculative and unreasonable. EPA ignored key factors that

drive a new unit’s utilization, particularly whether it was designed to provide baseload

or as a load-following unit. UARG Comments at 197, JA__. Subsequent operating

data from many of these “under-construction” units show EPA dramatically

underestimated their actual utilization. For example, North Carolina’s Lee gas unit

operated at an 81% annual net capacity factor in its first full year of operation, already

well above EPA’s 75% Building Block 2 target, let alone its 55% baseline assumption

for under-construction units, leaving no room for increased utilization. Id. Indeed, for

the set of units EPA designated as “under-construction” because they commenced

operation during 2012, the generation-weighted average capacity factor was 77% in

their first full year of operation. See id., Attachment C at 11 Tbl. 6, JA__. EPA’s

guidelines call on those units to devote another 20% of their capacity to displacing

coal-fired generation, for a total capacity factor of 92%.

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This error inflated the level of redispatch under Building Block 2, making the

performance standards infeasibly stringent. EPA should have excluded hypothetical

generation from under-construction units when calculating the guidelines because it

had no rational way to estimate their future unused capacity. EPA claims that even if

it overestimated available redispatch capacity, some of the under-construction units’

baseline generation will have a “replacement effect instead of an incremental one,”

yielding the same overall shift from coal- to gas-fired generation. 80 Fed. Reg. at

64,817 n.748. This is more baseless conjecture: EPA offers no evidence this

“replacement effect” exits, that it will outweigh EPA’s mistakes regarding utilization

of under-construction units, or that it will replace generation from coal-fired units

rather than more expensive renewable generation.

(iii) EPA Erred By Relying On Capacity From Gas-Fired Units’ Duct Burners For Redispatch.

Building Block 2 is further undermined by EPA’s erroneous reliance on

capacity from gas units’ duct burners for redispatch under Building Block 2. Response

to Comments (“RTC”) Ch. 3 § 3.2 at 172, EPA-HQ-OAR-2013-0602-36876, JA__.

Many gas units are equipped with duct burners that can temporarily boost power output

during peak load periods. UARG Comments at 206, JA__. Continual operation of

these duct burners is infeasible: their use introduces thermal stress that the unit is not

designed to withstand for prolonged periods, causing accelerated equipment wear. Id.

Duct burners also operate less efficiently than the rest of the unit, substantially

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increasing the unit’s heat rate (and thus its CO2 emission rate). Id. EPA’s sole

response—that “[d]uct burners are a component of [gas] capacity” and are therefore

included for redispatch—is conclusory and fails to address the serious problems

commenters raised. RTC Ch. 3 § 3.2 at 172, JA__. Consequently, EPA’s unsupported

75% capacity factor is in reality significantly higher.

For these reasons, EPA’s conclusion that Building Block 2 can achieve the

targeted level of generation shifting is precisely the type of “crystal ball” inquiry

prohibited by the case law. Portland Cement, 486 F.2d at 391.

c. Building Block 3.

Building Block 3 assumes that generation at affected units will be replaced “by

using an expanded amount of zero-emitting renewable electricity (RE).” 80 Fed Reg.

at 64,803, JA__. EPA determined the amount of available new renewables generation

by forecasting the growth in renewables generation anticipated through 2021 in the

absence of the Rule, and adding target renewables growth rates for 2022-2030 that

EPA predicts can occur as a result of the Rule. See id. at 64,807-09, JA__; GHG

Mitigation Measures TSD at 4-1 to 4-2, 4-6, JA__-__, __. Both forecasts are based on

unsupported, unrealistic assumptions about future growth. EPA thus has not shown

that the total renewables required by the Rule are adequately demonstrated, nor

shown that its Building Block 3 target is achievable.

EPA calculated growth levels of renewable energy anticipated to occur without

the Rule that are significantly greater than those projected by the U.S. Energy

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Information Administration (“EIA”)—the governmental entity charged with

forecasting electricity generation and demand. EPA projected that by 2020 renewable

energy generation, other than hydropower, will grow to 406,000 GWh; yet EIA

projects that it will grow only to 335,000 GWh. Compare Analysis of the Clean Power

Plan, Base Case SSR at Summary Tab16 with EIA Annual Energy Outlook 2015 at A-

31, EPA-HQ-OAR-2013-0602-36563, JA __. Moreover, EPA’s projection in the Rule

was significantly greater than its projection in the proposal that renewable energy

generation in 2020 would be only 299,000 GWh. See Analysis of the Proposed Clean

Power Plan, Base Case SSR at Summary tab.17

EPA failed to adequately explain why it increased its projections so significantly

in the Final Rule, or why the estimation of the entity responsible for such forecasts

should be discounted, particularly given that EPA is no expert on these issues. EPA

used 2012’s growth in renewables as the base growth level, but that year was

artificially inflated due to a tax credit that expired on December 31, 2012—causing

many projects to be shifted from 2013 to 2012. 21st Century Energy, “What’s In a

Target,” 13-15 (Jan. 2016), http://www.energyxxi.org/sites/

default/files/What%27s%20In%20a%20Target%20FINAL.pdf. EPA has failed to

16 Available at http://www.epa.gov/sites/production/files/2015-

08/base_case.zip, Base Case SSR Excel file, Summary Tab. 17 Available at http://www.epa.gov/sites/production/files/2015-

07/epa_base_for_the_proposed_clean_power_plan.zip, (Base Case-SSR Excel file, Summary Tab.

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adequately demonstrate the near-term renewables levels used in its BSER

determination.

With regard to renewable generation levels after 2021, EPA assumed that each

of the various types of renewables (solar, onshore wind, geothermal, and hydropower)

can achieve annual growth rates from 2024-2030 equivalent to the maximum annual

growth rate each achieved from 2010-2014. GHG Mitigation Measures TSD at 4-5,

JA__. In other words, EPA assumed that each technology will achieve its highest

historical one-year growth rate for seven consecutive years. EPA failed to explain the

basis for this extraordinary assumption. Rather, it appears once again to be the type of

“crystal ball inquiry” that cannot support a BSER determination.

A closer look at the numbers reveals how disconnected from reality EPA’s

assumption truly is. EPA assumed wind power on average can achieve a capacity

factor of 41.8%, when historical average capacity factors across the United States

from 2008-2014 range between 28.1% and 34%. Compare GHG Mitigation Measures

TSD at 4-3, JA__, with EIA, Electric Power Monthly at Table 6.7.B. (Feb. 2014), EPA-

HQ-OAR-2013-0602-0162, JA __. While technologies may be expected to improve

over time, any such improvements will likely be offset by the need to place an

increasing amount of wind generating capacity in less optimal locations. In any event,

EPA failed to adequately explain how average wind capacity factors can be increased

by the approximately 30% it assumes.

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Why does this matter? It matters because, if EPA’s crystal ball guesses turn out

to be wrong (as the record predicts they will), the results will be disastrous. Under the

Rule, because no gas unit can comply with the applicable performance rates, any

generation produced by a gas unit must be “offset” by ERCs from Building Block 3.

40 C.F.R. § 60.57954(b). As a result, if no ERCs were available from Building Block 3,

there would also be no ERCs for Building Block 2, with the result that no gas or coal

unit could generate any electricity. Every shortfall in the number of Building Block 3

ERCs needed for gas units to increase their capacity factor to 75% will result in a

shortfall in ERCs that coal units need to generate electricity. Consequently, if EPA’s

Building Block 3 assumptions are not supported, not only will there be a shortfall in

the generation produced by Building Block 2 and 3, but, even more troubling,

generation that could be produced by coal and is needed to meet the shortfall from

Building Blocks 2 and 3 will not be able to be produced. This “death spiral” that

EPA’s “system” creates underscores the critical error EPA made in finding that

Building Block 3 is “adequately demonstrated” and “achievable.”

In the end, EPA based its Building Block 3 analysis not on historically

demonstrated levels of renewable generation, but on unsupported, highly speculative

assumptions that far exceed both current projections and average historical growth

rates. EPA also failed to assess any of the real world considerations associated with

such massive growth, including where the new generating resources will be built, who

will build them, and how will they be integrated into the existing electrical grids.

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Southern Company Comments at 153-55, JA__. Building Block 3 is thus

impermissibly based on speculation and conjecture.

d. EPA Failed To Account For Application Of BSER On Generating Units’ Emission Rates.

EPA’s Building Blocks also fail to account for how application of the BSER

will negatively impact generating units’ emission rates. To calculate the guidelines, in

each interconnection EPA used the overall average 2012 CO2 emission rates for coal

units (adjusted downward by the Building Block 1 target) and gas units. Goal

Computation TSD at 10, 16-17, JA__. But EPA ignored comments demonstrating

that implementing BSER will raise the CO2 emission rates of those units above 2012

levels. For coal units, the BSER is based on reducing those units’ utilization, which

EPA admits increases CO2 emission rates. For some units, low load operation can

increase heat rate by 10% or more, eclipsing any Building Block 1 heat rate

improvements. GHG Mitigation Measures TSD at 2-34, JA__; Reconstructed EGU

TSD at 4, JA__; UARG Comments at 209-10, JA__.

For gas units, implementing BSER will involve increasing utilization of less

efficient units that were designed for optimum performance when following load (i.e.,

not acting as baseload). UARG Comments at 210, JA__. These units emit CO2 at

higher rates when used more heavily, increasing the overall emission rate of the

subcategory. See 79 Fed. Reg. at 34,980, JA__ (admitting some gas units “are designed

to be highly efficient when operated as load-following units” but are less efficient at

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baseload). Heavy use of gas units’ duct burner capacity, see supra at II.B.1.b.iii will also

raise those units’ CO2 emission rates. EPA’s failure to account for these effects on

fleet average emission rates further undermines its BSER calculation.

2. EPA Has Failed To Account For Grid Reliability Or Infrastructure Needs.

EPA’s BSER is also fatally flawed because EPA failed to meaningfully assess

the massive infrastructure build-out and upgrades that must occur or the Rule’s

impact on the reliability of the electric grid. EPA has not shown its plan will work, if

for no other reason than it has failed to consider fully and adequately the important

questions of transmission infrastructure and reliability.

a. EPA Failed To Meaningfully Assess The Need To Build New Infrastructure.

EPA failed to meaningfully assess the new infrastructure that will be required

to implement Building Block 2 and 3’s generation shifting. Replacing fossil generation

with new generation requires transmission infrastructure. EPA thus must establish

that the replacement generation contemplated by its BSER can be delivered in a

manner that ensures reliable power to meet user demands in all parts of the country.

EPA has not made that showing. EPA also failed to demonstrate that the existing gas

pipeline infrastructure would be sufficient to meet the substantially increased demand

for gas under the Rule. Southern Company Comments at 121-24, 220, JA__.

Instead of assessing how new infrastructure will be created and paid for, EPA

incorrectly assumes little additional infrastructure will be needed. See, e.g., 80 Fed. Reg.

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at 64,801, 64,810, JA __. EPA failed to demonstrate that this assumption is anything

but a speculative, “crystal ball” hope. Indeed, EPA’s assumption is belied by the

chorus of warnings from the experts.

For example, the North American Electric Reliability Corporation (“NERC”),

the regulatory authority charged with ensuring the reliability of the North American

bulk power network, concluded that the Rule’s “transformative shift” in electricity

generation would “lead[] to the need for transmission and gas infrastructure

reinforcements.” NERC, Potential Reliability Impacts of EPA’s Proposed Clean

Power Plan at vii, EPA-HQ-OAR-2013-0602-37007, JA__. NERC noted that

thousands of miles of new high voltage transmission would be required to satisfy

reliability and contingency analysis requirements. Id. at vii, 32, 34, JA__. Similarly,

Regional Transmission Organizations (“RTOs”) charged with operating the system to

balance generation and demand warned that substantial new infrastructure was

needed to ensure reliability. See, e.g., Midcontinent Independent System Operator, Inc.

Comments at 3, EPA-HQ-OAR-2013-0602-22547, JA__; Southwest Power Pool

Comments at 3, EPA-HQ-OAR-2013-0602-20757, JA__.

States and utilities also commented on the proposal’s lack of transmission

capacity to support generation shifting in various parts of the nation. See, e.g., Southern

Company Comments at 219-21, JA__-__; Montana Public Service Comm’n

Comments at 9, 11-12, EPA-HQ-OAR-2013-0602-23936, JA__, __-__; Mississippi

Public Service Commission Comments at 21-23, EPA-HQ-OAR-2013-0602-22931,

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JA__; North Dakota Department of Health Comments at 23, EPA-HQ-OAR-2013-

0602-24110, JA__; West Virginia Department of Environmental Protection

Comments at 35, 62, EPA-HQ-OAR-2013-0602-23540, JA__; Public Utility

Commission of Texas (“PUCT”) Comments at 42, EPA-HQ-OAR-2013-0602-23305,

JA __. For example, commenters noted that in Wyoming there is no significant gas

generation to absorb the load EPA mandates be taken from the State’s coal plants,

which means most of the required generation shifting must go to newly-constructed

wind farms; and this new generation will require substantial new transmission

infrastructure to ensure reliability. Basin Electric Comments at 25-29, JA__-__.

EPA offered little justification for its contrary conclusion, except to assert the

States will somehow work miracles with the “flexibility” allegedly afforded them. See

80 Fed. Reg. at 64,801, 64,810, JA__, __. This is not a demonstration; it is an

abdication.

b. EPA Failed To Ensure Reliable Electric Supply.

Additionally, to be “adequately demonstrated,” any system of emission

reduction for fossil units must ensure a reliable electric supply to avoid brownouts

and blackouts. EPA has failed to show that its system of alternative electric generation

will be reliable—in other words, that the lights won’t go out.

EPA conceded both that it lacks the expertise to assess grid reliability and that

it did not conduct a true reliability assessment of the generation shifting its “system”

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of emission reduction requires. See 80 Fed. Reg. at 64,874-81, JA__-__.18 EPA

recognized that “planning authorities and system operators constantly consider, plan

for and monitor the reliability of the electricity system with both a long-term and

short-term perspective.” Id. at 64,874, JA__. Further, it acknowledged such reliability

assessments are “multidimensional, comprehensive, and sophisticated.” Id. But

nowhere in the record did EPA provide such an assessment showing that application

of its ambitious BSER will result in the transmission necessary for a reliable electricity

system. Instead, EPA deferred for another day consideration of this critical issue, and

assumed States, system planners, and operators could “develop a pathway” to a

reliable electricity system. See id. at 64,876-77, JA__-__. Thus, this nation’s electricity

depends on the creation of a new “pathway” engineered by States and system

planners that the Rule’s architect cannot articulate.

Further, EPA’s conclusion that system reliability will not be affected is based

not on a legal or technical conclusion, but on an assumption baked into its Integrated

Planning Model—the model “must maintain adequate reserves in each region” and is

18 EPA did produce a document purporting to assess the reliability impacts of

the final Rule based on its modeling. Technical Support Document: Resource Adequacy and Reliability Analysis (“Reliability TSD”) at 1-2, EPA-HQ-OAR-2013-0602-36847, JA __-__. Rather than assessing reliability in a meaningful way, it merely “assumes that adequate transmission capacity exists to deliver any resources located in or transferred to [a] region.” Id. at 3, JA __. Tellingly, EPA does not even cite its analysis in discussing reliability in the preamble to the Rule. See 80 Fed. Reg. at 64,874-81, JA __-__. And EPA concedes that future analysis is required to assess reliability issues. Id. at 63,876-77, JA __-__.

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built around that assumption. Reliability TSD at 3, JA __; see PUCT Comments at 30,

JA __.

NERC, the RTOs, and others warned EPA of significant reliability concerns

with EPA’s proposal to quickly and radically restructure the nation’s energy supply.

See, e.g., Midcontinent Independent System Operator, Inc. Comments at 3, EPA-HQ-

OAR-2013-0602-22547, JA __ (expressing similar concerns); Southwest Power Pool,

SPP’s Reliability Impact Assessment of the EPA’s Proposed Clean Power Plan at 3, 5-

6 (Oct. 8, 2014), JA__, ___-___(describing its reliability assessment of the proposed

rule); NERC, Potential Reliability Impacts of EPA’s Proposed Clean Power Plan,

Initial Reliability Review at 19, EPA-HQ-OAR-2013-0602-37006, JA__ (“NERC

Reliability Review”).

EPA largely brushed off these concerns. It failed to conduct its own

meaningful assessment or confront the issues posed by Southwest Power Pool’s

assessment. It failed to address the need for a reliability safety valve; and its “reliability

safety mechanism” does not address the problem, as it provides only temporary relief

for catastrophic events like floods and offers States no flexibility to adjust either the

emission requirements or the schedule to address reliability problems. 80 Fed. Reg. at

64,876, 64,878, JA __, __. Its vague statements about working “with FERC and DOE

… to help ensure continued reliable electric generation and transmission” offer no

reasoned discussion of the issue and no assurance that its plan will work. And its

assurances that the Rule provides “flexibility” and a “gradual” compliance schedule

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ducks rather than confronts the issue, id. at 64,875-76, JA __, reflecting EPA’s wish-

upon-a-star approach.

Moreover, the “flexibility” EPA touts is not available in all areas, particularly in

ERCOT and in areas served by rural electric cooperatives. In these areas, unique

characteristics put such flexibility firmly out of reach, and showcase the reliability

problems posed by the Rule that EPA has failed to confront and adequately

demonstrate.

(i) The Electric Reliability Council Of Texas

In setting BSER based on national performance rates, EPA irrationally refused

to address the unique nature of the electric market in Texas. Texas is the only State

that has utilities operating in each of the nation’s three electrical interconnections:

ERCOT, the western interconnection, and the eastern interconnection.

Approximately 90% of Texas electricity consumption (covering 75% of Texas’s land

mass) occurs within ERCOT. http://www.ercot.com/about/profile/. It is a unique

“power island,” separated from the nation’s eastern and western interconnections by

asynchronous ties that inhibit cross-interconnect electric transmission.19 This means

nearly all “generation shifting” would have to occur within Texas. See PUCT

Comments at 31, JA__; Texas Comm’n on Environmental Quality’s (“TCEQ”)

19 ERCOT can import a limited amount of megawatts from outside its grid. See

ERCOT 2014 State of the Grid Report at 7, http://www.ercot.com/content/news/ presentations/2015/2014%20State_of_the_Grid_Web_21015.pdf.

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Comments at 2, EPA-HQ-OAR-2013-0602-22305, JA__; Luminant Comments at 49,

JA__. Texas thus cannot reduce its coal generation and purchase and import gas-fired

or renewable generation from a generator in another State at the levels EPA

mandates. PUCT Comments at 31; TCEQ Comments at 2. Compliance with the Rule

would pose significant challenges to maintaining reliability within ERCOT.

The Rule would supplant ERCOT’s economic dispatch model operating in a

uniquely competitive market. PUCT Comments at 10, JA__. Because ERCOT

investor-owned utilities have been separated into generation, transmission and

distribution, and retail services companies—with only the transmission and

distribution function subject to traditional regulation—units bear the risk of owning

and operating their assets without guaranteed recovery of their costs or profit through

regulated utility rates. See Tex. Util. Code Ann. § 39.001; PUCT Comments at 1, 4,

JA__, __. In the absence of long-term power contracts, the ERCOT market is

operated through unit-specific bidding and dispatch, with ERCOT using the

generation with the lowest bids to serve load, subject to transmission constraints.

PUCT Comments at 48, JA__. Bids are generally made reflecting the short-run

marginal costs of the units and dispatch decisions are made by ERCOT on the basis

of those bids. Id. at 43, JA__. Therefore, units in this competitive energy-only market

are already motivated to make efficiency improvements to their plants. Id.

EPA has ignored concerns from PUCT and Luminant regarding these impacts

in the ERCOT Market. See Luminant Comments at 66-68, JA__-__; PUCT

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Comments at 8-10, 37-38, 42-44, 48-51, JA at __-__, __-__, ___-__, __-__. EPA

acknowledged that “all of the lower-48 states, with the exception of Texas, are part of a

multi-state, regional grid.” Legal Memorandum for Proposed Carbon Pollution

Emission Guidelines for Existing Electric Utility Units at 91, EPA-HQ-OAR-2013-

0602-0419, JA__ (emphasis added). The Federal Power Act also recognizes the

limited nature of federal jurisdiction over the unique ERCOT market. 16 U.S.C. §

824(b); see also PUCT Comments at 8 n.12, JA__. EPA ignored these critical

distinctions in the Rule.

EPA’s only answer is the Rule’s so-called “flexibility.” 80 Fed. Reg. at 64,665,

64,880, JA__, __. But EPA’s “central” assumption of a multi-state electricity system

that provides this “flexibility” and underlies its BSER is simply not applicable to

Texas. 79 Fed. Reg. at 34,878, JA__. EPA is not an expert in electric grid reliability,

Del. Dept. of Natural Res. & Envtl. Control v. EPA, 785 F.3d 1, 18 (D.C. Cir. 2015), and

its inexperience is evident here. EPA’s refusal to account for ERCOT’s unique status

and to heed ERCOT’s reliability concerns is arbitrary and capricious. Id.

(ii) Cooperatives

The Rule also will make it impossible for many electric cooperatives to provide

reliable, low cost electricity to rural America (including the poorest parts of the

nation) in compliance with their obligations under 7 U.S.C. § 901, et seq. Rural electric

cooperatives typically serve large, primarily residential, low-density service territories

in the poorest and most rural parts of the country. National Rural Electric

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Cooperative Association (“NRECA”) Comments at 2-3, 129-30, EPA-HQ-OAR-

2013-0602-33118, JA__-__, __-__.

The Rule severely restricts generation sources available to cooperatives, see

NERC Reliability Review at 19, JA__, many of which own a single coal unit and rely

on its high-capacity-factor operation for their generation. Generation & Transmission

Cooperative Fossil Group Comments (“G&T Fossil Comments”) at 21, EPA-HQ-

OAR-2013-0602-23164, JA__. These cooperatives have invested billions of dollars to

install state-of-the-art emissions controls on their coal units to comply with other

regulations. See NRECA Comments at 14, JA__; see also EPA, Regulatory Impact

Analysis for the Final Mercury and Air Toxics Standards 3-13 (Dec. 2011),

http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf. Severely constraining

or retiring the operation of coal units will in turn severely challenge cooperatives’

ability to serve their members and create substantial financial issues. NRECA

Comments at 52, JA__.

For example, the Arizona cooperatives serve 150,000 individual meters, spread

across a large rural service area. Arizona Electric Power Co. Comments at 2, EPA-

HQ-OAR-2013-0602-22972, JA__. Arizona Electric Power Company will be forced

to curtail coal and gas-fired generation or even retire some or all of its steam units by

2022 to comply. Id. at 49, JA__. Such closure jeopardizes electric reliability in

Southern Arizona. Id. at 29, JA__.

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Cooperatives do not have shareholders or equity. G&T Fossil Comments at 22,

JA __. All increased costs associated with the Rule must be borne by member-

customers through increased rates, which will have a devastating impact on the

communities served. Id.; Western Farmers Electric Cooperative Comments at 14, Dkt.

No. EPA-HQ-OAR-2013-0602-23644, JA__. Moreover, because many rural residents

do not have access to natural gas and must depend exclusively on electricity or

expensive propane and heating oil for warmth during cold months, electric

cooperative member-customers lack practical, affordable alternatives when their

electric rates rise. NRECA Comments at 2, JA __. In electric cooperative service

territories, increases in rates force difficult decisions about whether to heat or cool

houses even in extreme weather. Id. at 2-3, 129-30, JA __-__, __-__.

By failing to take the unique challenges of rural areas into account in its BSER,

EPA has failed to demonstrate its system is reasonably reliable—that rural customers

will still have an affordable and reliable electric supply.

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3. EPA’s BSER Is Not “Demonstrated” Or “Achievable” By Individual Sources.20

EPA compounds its first error—its failure to show that the individual Building

Blocks are adequately demonstrated on a grid-wide scale or that the individual targets

from those Building Blocks are achievable—by then combining them and further

speculating about how they will operate together and how individual sources can

achieve the performance rates.

EPA acknowledged that the BSER must “be available to an individual source …

[and] allow it to meet the standard.” 80 Fed. Reg. at 64,722, JA__ (emphasis added).

Moreover, EPA “recognize[d] the uniqueness and complexity of individual power

plants” and was “aware that there are site-specific factors that may prevent some

[units] from achieving performance equal to region-level assumptions for a given

technology.” Goal Computation TSD at 6, JA__. Yet EPA admittedly did not “mak[e]

those unit-level evaluations,” instead applying assumptions of what the source

category as a whole might achieve through application of the Building Blocks on a

regional basis. Id.; 80 Fed. Reg. at 64,779, JA__.

20 As discussed in the Core Issues Brief, EPA’s system of emission reduction is

unlawful because it is not based on pollution controls or process changes that can be accomplished at the source itself, but instead necessitates the construction of new renewable energy facilities and generation shifting. Even if these activities could be considered to be legally valid components of BSER under section 111(d), EPA would still have to show that individual sources will be able to employ such strategies to meet the ambitious emission guidelines on a per-source basis.

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This is fatal to the Rule. And while it may be difficult for EPA to demonstrate

that individual units can apply an industry-wide system as opposed to controls or

practices implementable at an individual facility, that is EPA’s statutory burden with

this Rule. It cannot be shirked simply because the scope of EPA’s BSER is

unprecedented. Further, as in National Lime Ass’n, EPA erred by establishing emission

guidelines without analyzing whether much of the industry can meet them, given the

great “variations in operations” of utilities around the country. 627 F.2d at 434.

4. The Rule is Not Saved by the Presumed Availability of a Trading Program.

EPA concedes that individual sources will not be able to achieve the Rule’s

performance rates through the Building Blocks, but nonetheless insists that

compliance can be achieved through “a wide range of emission reduction measures,

including measures that are not part of the BSER.” RTC Ch.1 §§ 1.0-1.5 at 179, JA__

(emphasis added). In particular, EPA states that emissions trading is “integral” to its

assessment of the BSER and the achievability of its emission guidelines. 80 Fed. Reg.

at 64,733-35, JA__-__. EPA cannot rely on actions that are not part of the BSER to

establish the achievability of its guidelines. It has neither established a trading program

nor analyzed the reliability or achievability of any such programs that might be

established by the States. Moreover, the restrictions EPA has placed on State trading

programs makes it far less likely that sufficiently robust programs will develop.

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EPA’s admission that sources will need to engage in trading to satisfy the

emission guidelines is itself a concession that the guidelines are not “achievable

through the application of [BSER]” as required by section 111(a)(1). This is again

fatal. EPA cannot establish emission guidelines based on its BSER, acknowledge that

those guidelines are unachievable in many cases through application of the BSER, and

then tell regulated parties they have the “flexibility” to apply other, non-BSER actions

to achieve the guidelines. While regulated parties often have flexibility to choose

alternative methods of satisfying a standard that has been shown to be achievable

through application of the BSER, that is far different than allowing EPA to rely on

non-BSER measures to show that the standard itself is achievable. This Court has

rejected this very argument before, holding that “the flexibility appropriate to

enforcement will not render ‘achievable’ a standard which cannot be achieved on a

regular basis.” National Lime Ass’n, 627 F.2d at 431 n.46.

Nor does EPA conduct any meaningful analysis to determine whether, even if

it could rely on trading, sufficiently robust trading systems will arise. For trading to be

relied upon to justify EPA’s BSER, several things must happen. First, because the

Rule does not establish (or even require the creation of) any trading mechanism,

States must individually adopt trading programs. Second, because in many instances

actions within particular States will be insufficient for the sources within the State to

comply, State plans must be coordinated to allow for interstate trading. Third,

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participants within these coordinated trading programs must generate and trade

enough credits to allow compliance for all sources.

EPA offers no analysis showing this will happen; it only “anticipates” that

“organized markets will develop.” 80 Fed. Reg. at 64,731-32, JA__-__. Anticipation is

not demonstration and does not satisfy the requirement that EPA offer a

“‘satisfactory explanation’” and take a “‘hard look at the salient problems.’” Portland

Cement, 665 F.3d at 187 (citations omitted).

EPA also cites instances where trading has been successfully employed in

connection with federal clean air programs. See 80 Fed. Reg. at 64,696-97, JA__-__;

Legal Memorandum Accompanying Clean Power Plan for Certain Issues at 105-10,

EPA-HQ-OAR-2013-0602-36872, JA__-__. But in each case, individual sources

could comply without relying on trading if it so chose. That distinction overwhelms

any possible comparison to the Rule, where trading is the only way to achieve

compliance.

Regardless, the mere fact that trading programs have been used before hardly

means trading programs will arise here, or that there will be sufficient credits for

sources to comply. Moreover, in each of those instances, an overarching set of federal

statutory or regulatory requirements established the trading program. See CAA §§ 401-

416. The NOx State Implementation Plan Call, Clean Air Implementation Rule, and

Cross-State Air Pollution Rule are all EPA-imposed federal implementation plans that

set up trading programs for States that contribute significantly to downwind

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nonattainment. 80 Fed. Reg. at 64,696, JA__. The Clean Air Mercury Rule established

a cap-and-trade program based on mercury reductions that could be achieved by

controls installed at individual units. Id. at 64,697, JA__. In stark contrast, the Rule

here does not establish any trading program, or even require States to allow for

trading in their individual State plans. At the same time, the Rule’s performance rates

cannot be met without ERCs, and EPA acknowledges trading is “integral” to BSER.

Additionally, the Rule imposes affirmative restrictions that will inhibit—rather

than encourage the development of—sufficiently robust trading mechanisms. These

restrictions include: requiring States to either enter into a formal multi-state plan or

adopt emission standards equal to the sub-category performance rates in order to

engage in interstate trading, 40 C.F.R. § 60.5750(d); prohibiting issuance of ERCs for

resources operating prior to January 1, 2013, id. § 60.5800(a)(1), see infra at III.B

requiring that the credit generating resource be located in a rate-based State, except

under limited circumstances, id. § 60.5800(a)(3); limiting ERC generation in mass-

based States to wind, solar, geothermal, hydro, wave, and tidal sources, id. §

60.5800(a)(3); prohibiting credits for CO2 emission reductions that occur outside the

electric power sector, id. § 60.5800(c)(3); and offering no meaningful way to take

advantage of unit retirements as a means of creating ERCs. These restrictive

provisions limit the ability of States to create a trading environment in which adequate

ERCs will be available at a reasonable price.

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EPA’s whole plan collapses if new trading programs do not germinate, yet EPA

has not shown they will ever do so.

C. EPA Imposes on States an Impossible Task of Implementing BSER to Achieve Required Emission Reductions.

Section 111(d) obligates the States to establish performance standards that

reflect the BSER. However, EPA’s BSER is a house of cards that collapses under the

weight of reality.

Given EPA’s failure to establish the adequate demonstration or achievability of

its three individual Building Blocks, it is hardly surprising that the Rule’s performance

rates are manifestly unachievable under “the range of relevant conditions” that affect

different sources in different States. Nat’l Lime Ass’n, 627 F.2d at 433. Many States

lack the resources that EPA’s BSER assumes or have unique geographic or

infrastructure limitations that prohibit or severely limit their potential to shift

generation to lower- or zero- emitting generation. See Section II.B.2., supra, Section V,

infra. These States cannot apply the Building Blocks that comprise BSER to even

approach the performance rates EPA is imposing on the States and their sources.

For instance, Montana must achieve a nearly 50% reduction in coal unit CO2

emissions by 2030.21 But Montana sources cannot apply BSER to achieve this level of

21 For Montana, the final rate-based CO2 emission goal for 2030 is 1,305 lbs

CO2/MWh (compared to a baseline rate of 2,481 lbs CO2/MWh), for a 47.4% emissions rate reduction goal; and the final mass-based goal is 11,303,107 short tons (Continued...)

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emission reduction because there are no gas units (or associated transmission) in the

State. Goal Computation TSD Appendix 5, JA__. Additionally, while Montana has

renewable energy potential, its sources cannot build enough renewable energy to

replace 50% of the State’s baseload generation or build the necessary transmission

capability by 2030. Montana Public Service Comm’n Comments at 9, EPA-HQ-OAR-

2013-0602-23936 (“MPSC Comments”), JA__. Its neighbor North Dakota is in a

comparable situation, with 99.4% of the fossil-fuel generation in the State coming

from coal in 2013.22 The State faces a 44.9% emission reduction requirement but has

no gas units in the State. Goal Computation TSD Appendix 5, JA__.

Similarly, Kentucky faces massive CO2 reduction requirements, but sources

cannot achieve those reductions within the State’s borders. Coal generation provides

over 90% of the State’s electricity needs, LG&E and KU Energy LLC Comments at

3, JA__; the only gas unit in Kentucky was under construction during the Rule’s

comment period, id. at 14, JA__; and Kentucky has little wind and solar potential,

UARG Comments at 243, JA__.

Kansas, North Dakota, West Virginia, and Wyoming face similar situations,

where 90% of their in-state fossil generation comes from coal units but sources within

those States have limited ability to replace that generation with gas and renewable

________________________ of CO2 (compared to an adjusted baseline level of 19,147,321 short tons of CO2), a 41% emissions reduction goal. Goal Computation TSD, Appendix 5, JA__.

22 http://www.eia.gov/electricity/state/NorthDakota/.

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generation. Wyoming Comments at 14-20, JA__; Kansas Department of Health &

Environment Comments at 7, EPA-HQ-OAR-2013-0602-23255, JA__; West Virginia

Department of Environmental Protection at 41-42, JA__. Similarly, Texas (operating

primarily within the limited ERCOT region) has significantly higher renewable

generation than the U.S. average and has already utilized the most promising sites for

renewable generation. Luminant Comments at 63-64, JA__-__.

Finally, as discussed above, the fact that EPA would allow States to develop

emissions trading systems under their state laws to achieve compliance does not save

the Rule. The Act requires States to establish performance standards for existing

sources within their own borders. § 111(d). EPA has not shown that it can require

States to rely on extraterritorial emissions credits in setting and achieving the

performance standards for sources within their borders. While EPA may consider the

electric power industry a “highly integrated” and “complex machine,” state laws are

not. EPA cannot impose on individual States the obligation to look beyond their

borders.

EPA therefore has failed to show that all States can apply the BSER to

approach EPA’s mandated emission guidelines.

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III. The Rule Arbitrarily Penalizes Many Sources Of Low- And Non-Emitting Generation Along With Companies And States That Have Already Taken Costly Actions To Reduce Emissions Of Greenhouse Gases.

To justify the Rule’s radical approach, EPA asserts the electric industry is

unique, that all its sources form an interconnected, “complex machine”—the electric

supply system. 80 Fed. Reg. at 64,725, JA__. Thus, it reasons, increases in generation

from one source affect generation from other sources, and electrons can freely flow to

wherever they are needed when existing units shut down. Id. For that reason, EPA

invented its new “system” of emission reduction based on forcing the industry to shift

to EPA’s favored sources of electricity.

EPA’s approach is arbitrary and capricious in two ways. First, it ignores a

significant part of the existing mix of electric generating sources that plays a

substantial role in how fossil fuel-fired units are dispatched and operated. Second, it

arbitrarily penalizes zero- and low-emitting generating facilities (including wind, solar,

and nuclear) that began operating before 2013. 40 C.F.R. § 60.5800(a)(1). In doing so,

EPA significantly disadvantages the States and companies that have been at the

forefront of addressing climate change.

A. EPA Arbitrarily Ignores A Large Part Of The Electric Supply System For Compliance Purposes.

It is hypocrisy for EPA to claim its system is based on the whole grid while it

ignores large parts of that grid: existing renewable energy, nuclear generation that

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provides approximately 20% of the nation’s power23 with zero emissions, hydro-

electric generation that supplies the majority of electricity in many regions of the

country, co-generation units, and waste-to-energy facilities with very low carbon

footprints. All are critical to the electric supply system and to reducing the demand for

electricity from fossil fuels. EPA arbitrarily excludes them as compliance options.

The existence of these EPA-disfavored non-fossil resources has driven many

companies’ electric supply resource decisions. For example, hydroelectric generation

dominates the supply of electricity in the Pacific Northwest, giving those States the

lowest average emission rates per megawatt hour in the country. See Portland General

Electric Comments at 18, EPA-HQ-OAR-2013-0602-23507, JA__. The seasonal and

variable nature of hydroelectric generation also dominates the other resource

decisions in the region. Id. at 33, JA__; 80 Fed. Reg. at 64,815, JA__. Yet, EPA failed

to consider the importance of maintaining existing hydroelectric power and its unique

characteristics in its analysis for Rule compliance. 80 Fed. Reg. at 64,735, JA__.

Similarly, companies that have invested in nuclear generation over the years have kept

their emission rates lower; yet EPA ignored the huge benefit nuclear units contribute

to zero-emission generation. Id.; Entergy Comments at 21-22, EPA-HQ-OAR-213-

0602-22874, JA__-__ . EPA essentially assumes these generation resources will

23 EIA, What is U.S. electricity generation by energy source,

https://www.eia.gov/tools/faqs/faq.cfm?id=427&t=3 (Mar. 2015).

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continue operating at similar levels in perpetuity, and fails to recognize the significant

role their continued operation will play in future dispatch and emissions performance

of the electricity sector.

Because EPA effectively ignored these resources, it “failed to consider an

important aspect of the problem.” Motor Vehicle Mfrs. Ass’n. v. State Farm Mut. Auto.

Ins. Co., 463 U.S. 29, 43 (1983). EPA cannot base a rule on the assumption that a large

part of the “system” it is regulating does not exist or that its status as of 2012 will

remain static forever.

B. The Rule Arbitrarily Discriminates Between Low- and Zero-Emitting Sources Built Before And After January 1, 2013.

No good deed goes unpunished. This Rule bears that out. In determining

whether a resource can count toward compliance, the Rule discriminates between

identical resources based on whether they were constructed before or after January 1,

2013. The existence of any cut-off date is arbitrary. It punishes entities that chose to

invest in zero- and lower-emission resources early to address the very problem EPA

seeks to tackle. It also creates harmful and perverse incentives for the future operation

of early-built resources. EPA acknowledges the “clearly emerging growth in clean

energy innovation, development and deployment,” 80 Fed. Reg. at 64,663; JA__, as

critical to reducing greenhouse gas emissions. Yet the Rule makes no allowance for

this early action. To the contrary, it uses these early actions as a way to impose on

those companies and States even more stringent performance rates.

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Several States’ experiences are illustrative:

• Over the past fourteen years, New Jersey entities invested $3.27 billion in

renewable energy and energy efficiency. New Jersey Department of

Environmental Protection Comments at 2, EPA-HQ-OAR-2013-0602-22758;

JA__; see also New Jersey Technical Comments at 5, EPA-HQ-OAR-2013-

0602-22758; JA__.

• In 2012, Kansas entities increased the State’s wind generation capacity

exponentially. See Existing Kansas Wind Farms, http://kansasenergy.org

/wind_projects.htm.

• Between 2005 and 2012, Minnesota entities invested $4 billion to reduce CO2

emissions by almost 21%. Xcel Energy Inc. Comments at 9-10, EPA-HQ-

OAR-2013-0602-22748; JA__.

• In the past 15 years, Washington State has invested more than $8 billion in

renewable energy sources. Pacific Coast Collaborative Comments at 2, EPA-

HQ-OAR-2013-0602-22947, JA__.

• Texas—which produced 23% of all wind energy produced in the United States

and more than twice as much wind energy as the next highest wind energy

producing state in 2012—is likewise being punished as a first mover in this

area. TCEQ Comments at 2, JA__.

Other examples abound.

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EPA’s arbitrary discrimination between identical power generation resources is

contrary to the Administrative Procedure Act and creates perverse market incentives.

See Indep. Petrol. Ass’n of Am. v. Babbitt, 92 F.3d 1248, 1258 (D.C. Cir. 1996). Even

though pre-2013 zero-emission sources provide precisely the same environmental

benefit as post-2013 sources, the Rule significantly disadvantages pre-2013 sources

without a plausible justification. EPA assumes that resources constructed before 2013

will continue operating at their present rates indefinitely, partially alleviating the need

for fossil fuel-based power. See 80 Fed. Reg. at 64,737, 64,897, JA__, __. Yet the Rule

will lead to the opposite result. EPA’s rule discounts the value of existing renewable

energy, incentivizes owners to defer or stop maintenance and helps create a fleet of

stranded renewable energy assets.

This trend will only increase when pre-2013 generators face diminishing value

as the full implementation of the Rule causes ERC value to increase. EPA simply fails

to recognize that in creating economic advantage for newer resources, it will render

less viable existing resources of identical environmental value. EPA should not be in

the business of picking winners and losers arbitrarily.

The discriminatory impact of EPA’s arbitrary cutoff date for compliance tools

is underscored by the circumstances confronting waste-to-energy facilities. Although

these facilities provide significant carbon emission reductions—every ton of

municipal solid waste directed to a waste-to-energy facility rather than a landfill avoids

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more than one ton of greenhouse gas emissions24—the technology is expensive,

64.6% more costly than landfilling. LGCRE Comments at 9-11, JA__, __.

That cost disparity jeopardizes communities’ continued reliance on waste-to-

energy, and ERC eligibility could be pivotal for sustained operation versus shutdown.

Pre-2013 facilities need revenue incentives such as ERCs “to make investments to

continue producing clean energy.” Absent such incentives, operators “may ultimately

choose to retire facilities rather than extend their lives.” Id. at 7-11, JA__, __; see

http://www.mprnews.org-/story/2010/10/12/ground-level-cities-in-crisis-red-wing

(Minnesota waste-to-energy facility closes due to high operating expense and low-cost

landfill alternative); http://energyrecoverycouncil.org/wpcontent/uploads/

2016/02/DMS-3307817-v3-CREA_Minutes-April_9_2015.pdf (waste-to-energy

facility in Los Angeles County faces possible shutdown due to declining electric

revenues). Moreover, while EPA acknowledges the role of waste-to-energy and other

pre-December 31, 2012 renewables in “keeping CO2 emissions lower than they would

otherwise be,” it speculates that denying these sources ERC eligibility will not affect

the net carbon reduction EPA projects. 80 Fed. Reg. at 64737, JA __. EPA’s

speculation is not supported by the record, and such arbitrary “unsupported

24 See Air Emissions from MSW Facilities, EPA,

http://www3.epa.gov/epawaste/nonhaz/municipal/wte/airem.htm#7; see also Bridging the Gap, UNEP at 37-38 http://www.unep.org/pdf/UNEP_bridging_gap.pdf (United Nations advises that waste sector emissions can be reduced 80% through significant diversion of landfilled waste to waste-to-energy).

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suppositions” require reversal. McDonnell Douglas Corp. v. U.S. Dept. of the Air Force, 375

F.3d 1182, 1186-87 (D.C. Cir. 2004).

EPA compounds these problems by imposing a discount on waste-to-energy-

produced electricity. Although waste-to-energy’s throughput is biogenic (paper, food

waste, etc.) as well as anthropogenic (e.g., non-recyclable plastics), throughput is

typically at least 40% anthropogenic. http://www.ecomaine.org/education/

NAWTEC%20Maritatopercent20Hewes%20paper.pdf. Under the Rule, State plans

will be allowed to qualify only the biogenic portion as renewable. 40 C.F.R.

§ 60.5800(a)(4)(iii). Aside from contradicting the greenhouse gas emission reduction

objective at the heart of the Rule and EPA’s recognition of the significant reductions

waste-to-energy achieves, the discount will mean lower energy revenues for these

facilities and further jeopardize local governments’ ability to sustain their higher cost.

EPA’s rationale for discounting waste-to-energy electricity is nowhere stated. EPA

acknowledged comments opposing such a discount, see RTC Ch. 3 §§ 3.5-3.12 at 360-

63, JA__-__, but did not respond. That failure requires reversal. Del. Dep‘t of Natural

Res, 785 F.3d at 11.

The same is true of the nuclear industry. Companies have invested millions of

dollars in recent years to increase both the capacity and the capacity factors from

nuclear units. For example, Entergy undertook a 178 MW uprate of its Grand Gulf

nuclear station in 2012 and began operating at close to its new, higher capacity in

September of that year. Entergy’s Comments at 21-22, JA__, __. Because nuclear

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units operate as baseload generators, the 178 MW of new generation creates over

three times the benefit of, for example, wind generation that achieves only a 33%

capacity factor. Yet, under the Rule, because Entergy undertook the uprate in 2012

instead of three months later, it receives no credit and never will. New Jersey also

made large investments toward increasing the three nuclear power plants’ output prior

to 2013. See New Jersey Department of Environmental Protection Comments at 2, 4,

JA__, __; see also New Jersey Technical Comments at 22-24, JA__-__.

All these investments produced environmental benefits, reduced emissions and

helped spur the renewable energy industry. The cost for those benefits is already being

borne by the ratepayers in these States. Yet EPA’s Rule provides them with no

benefit. Further, EPA simply presumes that all of these good acts will remain in place

forever. But EPA’s own Rule effectively discourages that outcome.

EPA’s date cutoff also arbitrarily penalizes renewable resources that were

installed during 2012 and only generated for a portion of the year. EPA states that

“generation from . . . [renewable energy] capacity installed prior to 2013 has been

excluded from the EPA’s calculation of the CO2 emission performance rates in the

emission guidelines.” 80 Fed. Reg. at 64,897, JA__. This explanation does not account

for renewables that became operational during 2012 because generation from such

renewables would not have been present during the entire year. A portion of

generation from these sources is completely lost: it is neither part of the baseline nor

is eligible to generate compliance credits.

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C. EPA Unlawfully Prohibits The Use of Enhanced Oil Recovery That Also Results In Associated CO2 Storage.

The Rule limits the injection of CO2 from affected facilities to Subpart RR-

compliant facilities. See 40 C.F.R. § 60.5860(f)(2). Enhanced oil recovery operators

inject CO2 into oil- and gas-bearing formations to recover stranded hydrocarbons,

reporting the quantity of CO2 injected under 40 C.F.R. Part 98, Subpart UU. The Rule

limits the storage of CO2 from affected units to operations that report under the far

more burdensome requirements of Subpart RR. It thus functionally prohibits facilities

from using CO2 in enhanced oil recovery. 40 C.F.R. § 60.5860(f)(2). That is unlawful

for two reasons.

First, this requirement was nowhere in the Proposed Rule. In fact, EPA

maintained that it was not considering carbon sequestration as a BSER component.

See 79 Fed. Reg. at 34,857, JA__.

Second, the restriction tramples state mineral property laws and private mineral

leases. See 58 C.J.S. Mines and Minerals § 403. Compliance is impracticable for many

operations that commingle CO2 from affected units and other sources. And the Rule

conflicts with prior EPA statements advocating enhanced oil recovery for carbon

sequestration. See 79 Fed. Reg. at 1,473-74; id. at 1,478-479. Indeed, it undermines the

government- and ratepayer-funded plan to use enhanced oil recovery at a first-of-its-

kind integrated gasification combined cycle power plant in Kemper County,

Mississippi. See id. at 1,435. EPA dismissed these concerns as a matter of cost alone.

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See 80 Fed. Reg. at 64,884, JA__. That was error. The Subpart RR condition should be

vacated.

IV. EPA Has Failed To Consider Important Aspects Of The Rule.

The Supreme Court has repeatedly recognized that an agency decision is

arbitrary and capricious where the agency has “failed to consider an important aspect

of the problem.” State Farm, 463 U.S. at 43. “[J]udicial review can occur only when

agencies explain their decisions with precision, for ‘[i]t will not do for a court to be

compelled to guess at the theory underlying the agency’s action….” Am. Lung Ass’n. v.

EPA, 134 F.3d 388, 392 (D.C. Cir. 1998) (citing SEC v. Chenery Corp., 332 U.S.

194,196-97 (1947)). EPA has failed to consider important aspects of the Rule and

made critical errors in its emission guidelines as a result.

A. The Rule Impermissibly Regulates New Units.

The Rule requires that mass-based state plans include provisions to prevent

“leakage,” or “shifts in generation to unaffected fossil fuel-fired sources that result in

increased emissions, relative to what would have happened had generation shifts

consistent with the [BSER] [] occurred.” 80 Fed. Reg. at 64,822-23; JA__-__.

“Unaffected fossil fuel-fired sources” refers to new units subject to EPA’s

performance standards under section 111(b). CAA § 111(b). The leakage requirement

must be vacated, as EPA has no authority under section 111(d) to require that States

prevent the increased dispatch of new units.

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Measures to prevent the dispatch of new units unlawfully subject such units,

which are regulated under Section 111(b), to a state plan under section 111(d). This

violates the plain language of the CAA. See also 80 Fed. Reg. at 65,039; JA__. The

CAA establishes two avenues for applying performance standards to sources: (i)

regulation of “new sources” under section 111(b), or (ii) regulation of “existing

source[s]” under section 111(d). These two avenues are mutually exclusive, as a unit

cannot be both a new unit and an existing unit. Under section 111(a)(6),“[t]he term

‘existing source’ means any stationary source other than a new source.” CAA § 111(a)(6)

(emphasis added). In contrast, section 111(a)(2) defines a “new source” as “any

stationary source, the construction or modification of which is commenced after the

publication of regulations (or, if earlier, proposed regulations) prescribing a standard

of performance under this section which will be applicable to such source.” Id. §

111(a)(2). This statutory language clearly and unambiguously establishes non-

overlapping definitions of “new” and “existing” units, leaving no room for any

alternative interpretation. See Chevron v. Natural Res. Def. Council, 467 U.S. 837, 842-43

(1984). Even EPA recognizes that sources may be subject only to section 111(b) or

section 111(d), and not both. Proposed Federal Plan, 80 Fed. Reg. at 65,039.

Accordingly, EPA has no authority to regulate the dispatch of new units under section

111(d), and the leakage requirement must be vacated. EPA cannot require States to

implement rule elements the Agency itself has no authority to implement.

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B. EPA Failed to Establish The Necessary Subcategories For Coal Types And Generation Technologies.

For new sources, the Act permits EPA to establish different emissions

limitations for subcategories of units, and EPA regularly does so. CAA § 111(b)(2)

(EPA “may distinguish among classes, types, and sizes within categories” (emphasis

added)); see 80 Fed. Reg. at 64,760, JA__. EPA’s section 111(d) rules go further for

existing sources, mandating adoption of subcategories where existing sources have

unique characteristics. 40 C.F.R. § 60.22(b)(5) (EPA “will specify different emission

guidelines or compliance times or both for different sizes, types, and classes of

designated facilities when costs of control, physical limitations, geographical location,

or similar factors make subcategorization appropriate.” (emphasis added)).25 EPA

acted arbitrarily and capriciously by failing to do so here, particularly for lignite coal-

fired units.

EPA’s own past rulemakings and unique lignite unit characteristics demonstrate

the necessity of subcategorization. For example, EPA previously established

subcategories for lignite-fired coal units in the Mercury and Air Toxics Standards rule

under section 112. 77 Fed. Reg. 9,304, 9,379 (Feb. 16, 2012); see Luminant Comments

at 82-86, JA__-__.

25 This provision contrasts with others that simply allow EPA to subcategorize.

Cf. CAA § 111(b)(2).

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Here, the record shows that mine-mouth lignite units have significantly higher

costs of control (i.e., retirement or curtailment) compared to other units in the

category. Luminant Comments at 83-84, JA__-__. Lignite-fired units are always

located at or near the mine that feeds it due to transportation cost constraints, and

retirement of the unit is thus certain to cause shutdown of the mine and breach of

long-term fuel supply contracts, with magnified economic impacts on the surrounding

communities. See NACoal Comments at 20-22, JA__-__. EPA nonetheless treated all

coal units the same in the Rule, reasoning that “each affected [unit] can achieve the

performance rate by implementing the BSER.” 80 Fed. Reg. at 64,760, JA__. Given

the unique constraints faced by lignite-fired units, the failure to subcategorize was

arbitrary and capricious.

C. EPA Failed to Consider Renewable Energy’s Limitations.

EPA failed to consider the inherent limitations on generation and distribution

of energy from renewable energy sources in electric markets. The Rule fails to address

various issues associated with incorporating substantial amounts of renewable

generation into the electric grid, including its substantial reliability impacts (including

voltage support, system inertia, and stability issues), as well as transmission planning,

siting, and construction issues. Southern Company Comments at 153-56, JA__-__.

States like Texas have seen these limitations firsthand. Wind generation in Texas

generally produces only a fraction of its output during times of peak demand, thereby

making the availability of fossil generation critical for maintaining reliability; the Rule

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fails to accommodate this shortcoming. PUCT Comments at 61, JA__ (EPA used a

capacity factor for Texas wind of between 39 and 41%, in contrast to a prior ERCOT

estimate of 8.7% availability during summer peak demand); Luminant Comments at

71, JA__ (wind generation is volatile); Montana Public Service Comm’n Comments at

11-12, JA__-__ (renewables’ transmission constraints). EPA assumed unrealistically

optimistic and unsupported capacity factors for renewable energy generation. See

“What’s In a Target,” supra, at 17-20. It also gamed its analysis to show much lower

cost associated with renewables by lowering coal generation substantially below the

levels of the Base Case in the Proposed Rule and substantially below EIA’s long Term

Coal Generation forecast as well. EVA Report 17-24, 64-68, http://www.nma.org/

pdf/EVA-Report-Final.pdf.

D. EPA’s Cost-Benefit Analysis Is Fundamentally Flawed.

Section 111(a) requires consideration of costs. EPA, however, diminishes the

Rule’s costs by inflating its purported benefits in a manner outside the CAA’s scope.

The Rule is therefore arbitrary and capricious. See Michigan v. EPA, 135 S. Ct. 2699,

2707 (2015) (it is not “rational … to impose billions of dollars in economic costs in

return for a few dollars in health or environmental benefits”).

EPA monetizes the Rule’s climate-related benefits using the Global Social Cost

of Carbon. The Global Social Cost of Carbon’s flaws are well known: the Interior

Department calls it “misleading” because it excludes “the social benefits of energy

production.” Dep’t of Interior, Federal Coal Leases COC-0123475 01 and COC-

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68590, at 4-26 (Jan. 2016), http://www.wrcc.osmre.gov/initiatives/

colowyo/documents/Colowyo_Collom_EA_CH%201-7.pdf. The National Academy

of Sciences says it is outdated, inaccurate, and uncertain. Nat’l Academy of Sciences,

Assessment of Approaches to Updating the Social Cost of Carbon, at 1 (2016). Academics

characterize it as “meaningless,” “close to useless,” and “arbitrary.” Robert S. Pindyck,

Climate Change Policy: What Do the Models Tell Us?, J. Econ. Lit. 51(3), 860-72 (2013),

http://dspace.mit.edu/openacces-disseminate/1721.1/88036. EPA’s reliance on this

flawed tool is fatal.

Further, the CAA expressly forecloses use of the Global Social Cost of Carbon

because foreign benefits exceed the cost-benefit analysis’ permissible scope. The Act’s

purpose is exclusively domestic: “[T]o protect and enhance the quality of the Nation’s

air resources [for] … its population.” CAA § 101(b) (emphases added). EPA has

acknowledged this. 74 Fed. Reg. 66,496, 66,514 (Dec. 15, 2009). Congress explicitly

says when EPA may consider foreign benefits. E.g., CAA § 115.

Only 10% of the claimed global benefits from reducing CO2 emissions accrue

to the United States. UARG Comments, Supp. No. 12, Social Cost of Carbon TSD at

11, EPA-HQ-OAR-2013-0602-22768, JA __. Stripping foreign benefits from the

Rule’s cost-benefit analysis reduces climate-related benefits to, at most, $0.3 billion in

2020 and $2.0 billion in 2030. See Regulatory Impact Analysis (“RIA”) at ES-22, EPA-

HQ-OAR-2013-0602-37105, JA__. The Rule’s claimed (and underestimated) costs

($2.5 billion in 2020 and $8.4 billion in 2030) dwarf these domestic benefits.

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EPA also failed to account for real-world effects that suppress the claimed

benefits, further skewing the cost-benefit analysis. The Rule does not account for

emissions resulting from the Clean Energy Incentive Program, which enables States to

emit up to 300 million tons of CO2 without it counting against their emission goals.

80 Fed. Reg. at 64,829, JA__. This further diminishes the Rule’s benefits. EPA admits

this program “is not reflected” in its cost-benefit analysis. RIA at 3-45, JA__.

The Rule also overstates emissions reductions by ignoring that industries

respond to energy price increases by shifting production abroad. This depresses

benefits because those businesses do not reduce—and may increase—emissions. This

result will inevitably occur because the Rule will raise electricity costs. Rather than

account for this issue, EPA simply notes the phenomenon and moves on. Id. at 5-6,

JA__-__.

EPA also failed to consider the 30,000 premature deaths associated with the

loss of disposable income resulting from the Rule. Oil and Gas Industry

Organizations and Participants-II Comments at 18-20, EPA-HQ-OAR-2013-0602-

25423, JA__-__.

Because EPA “entirely failed to consider” these “important aspect[s] of the

problem,” State Farm, 463 U.S. at 43, EPA’s cost-benefit analysis cannot support the

Rule, and the Rule should be vacated. Nat’l Ass’n of Home Builders v. EPA, 682 F.3d

1032, 1040 (D.C. Cir. 2012) (“[A] a serious flaw undermining [cost-benefit] analysis

can render the rule unreasonable.”).

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V. The Rule Should Have Been Tailored To Individual State Circumstances.

The arbitrariness of EPA’s actions is demonstrated by the unique harm that

will befall many States under the Rule because EPA failed to take into account

individual States’ circumstances. The resulting harm is exemplified by the following

experiences of Arizona, New Jersey, North Carolina, Utah, Wisconsin, and Wyoming.

A. In Calculating Wisconsin’s Baseline Emissions, EPA Improperly Disregarded A Nuclear Plant’s Imminent Retirement.

EPA improperly disregarded the imminent retirement of a nuclear power plant

in using 2012 data to calculate Wisconsin’s starting point from which the Plan’s

reductions are based. 80 Fed. Reg. at 64,813-27, JA__-__. The Kewaunee plant—

which EPA acknowledged represented over 7% of Wisconsin's generation in 2012,

EPA’s RTC Ch. 4, §§ 4.5-4.9 at 25, JA__—was decommissioned in May 2013. Wis.

Dep’t of Nat. Res. Comments, pt. 3 at 1, EPA-HQ-OAR-2013-0602-23541, JA__

(“WDNR Comments”). The majority of that lost generation was replaced with fossil-

fuel generation from the existing fleet in 2013 and beyond.

EPA recognized the retirement in the proposal, 79 Fed. Reg. at 34,870, JA__,

but failed to increase the baseline to account for the replacement generation after

2012 in either the Proposed or Final Rule. 80 Fed. Reg. at 64,813-19, JA__-__; see also

RTC Ch. 4, §§ 4.5-4.9 at 25, JA__. EPA did increase other States’ baselines, such as

Minnesota’s, based on a coal-fired generation unit that was temporarily offline in 2012

but resumed operation in 2013. 80 Fed. Reg. at 64,815, JA__; RTC Ch. 4 §§ 4.5-4.9 at

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8-9, JA__. Had EPA applied this approach to Wisconsin’s final goal, its target would

have been approximately 6.5% higher. Wisconsin raised this issue to EPA, WDNR

Comments, pt. 3 at 1, JA__, but EPA ignored it.

EPA’s willful blindness is unlawful in three respects. First, its failure to account

for the known issues with Kewaunee’s retirement, EPA’s RTC Ch. 4 §§4.5-4.9 at 25,

JA___, demonstrates a failure to “articulate a satisfactory explanation for its action

including a rational connection between the facts found and the choice made.” State

Farm, 463 U.S. at 43. Second, failing to treat similarly situated States alike (that is,

Wisconsin like Minnesota)—without giving a rational explanation—contravenes the

principle that “[a]n agency must treat similar cases in a similar manner unless it can

provide a legitimate reason for failing to do so.” Indep. Petrol. Ass’n v. Babbitt, 92 F.3d

1248, 1258 (D.C. Cir. 1996); accord Kreis v. Sec’y of Air Force, 406 F.3d 684, 687 (D.C.

Cir. 2005). Finally, by failing to respond to Wisconsin’s comments regarding

Kewaunee, the agency failed to respond to all “relevant” and “significant” public

comments. Home Box Office, Inc. v. FCC, 567 F.2d 9, 35-36 & n.58 (D.C. Cir. 1977).

B. EPA Failed To Truly Account For Trading Between States And Indian Tribes in Arizona And Utah.

Even if the Court finds that a trading platform is a lawful basis for establishing

BSER under section 111(d), EPA’s failure to recognize a uniform method of trading

between mass-based and rate-based jurisdictions imposes an arbitrary, capricious, and

unlawful hardship on States like Arizona and Utah. In determining States’ obligations,

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EPA contends it can derive mass-based targets from rate-based targets. 80 Fed. Reg.

at 64,743, JA__. If EPA can fairly convert a rate-based goal to a mass-based goal for

establishing state carbon emission targets, it follows that these same conversions

could be used to facilitate trading between rate- and mass-based States. EPA’s failure

to allow for such trading prohibits rate- and mass-based States and sovereign Tribes

from working together.

This impediment works a unique harm in Arizona, where a substantial

component of the State’s energy is generated on tribal lands belonging to the Navajo

Nation, which will be directly regulated by EPA. 80 Fed. Reg. at 65,033, JA __

(proposing to find it “necessary and appropriate for EPA to regulate units on tribal

land). Whatever emission standards are imposed on Arizona’s generation will

foreclose many potential regulatory avenues that ought to be available. For example, if

EPA regulates the Navajo Nation under a mass-based plan, Arizona would be

compelled to also adopt a mass-based plan or else forfeit any ability to coordinate

with this major aspect of the State’s basic infrastructure. Trading between types of

plans is critical, if trading is approved by this Court as part of the BSER.26

The Bonanza Power Plant owned by Utah-based Deseret Power Electric

Cooperative is also located on Tribal lands and is therefore under federal jurisdiction.

26 This is also important for Utah, a part of the Pacifcorp service territory,

which includes States that are currently planning both rate- and mass-based compliance. www.pacificorp.com/about/co.html.

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See 80 Fed. Reg. at 64,705, JA__. The plant is an essential part of the Utah power

system, and trading between types of plans (if lawful) will be critical.

C. EPA Ignored Wyoming’s Unique Circumstances.

EPA’s nationally-applicable guidelines ignore a number of State-specific

circumstances in Wyoming. 80 Fed. Reg. at 64,816-19, JA__-__. First, EPA’s

significant changes to the BSER Building Blocks disproportionately imposed stringent

emission reduction goals on Wyoming—the 6% reduction it was asked to meet in the

Proposed Rule nearly doubled in the Final Rule. Compare 79 Fed. Reg. at 34,895, JA__,

with 80 Fed. Reg. at 64,824, JA__. For Wyoming’s coal fleet, with higher emission

rates from air-cooled plants, the initial overall rate is 2,331 lbs/MWh, which requires

an 11.57% reduction to reach the eastern interconnection rate adjusted for Building

Block 1. Wyoming Public Service Comm’n at 34-38, JA__-__ (discussing the

impossibility of attaining either set of goals).

EPA also failed to take into account Endangered Species Act concerns specific

to Wyoming. In analyzing the Building Blocks, EPA relied on data from the National

Renewable Energy Laboratory (“NREL”), 80 Fed. Reg. at 64,807, JA __despite the

fact that the NREL explicitly states it did not capture “site-specific challenges of

building electricity infrastructure.” 2015 Standard Scenarios Annual Report: U.S.

Electric Sector Scenario Exploration. National Renewable Energy Laboratory at 19,

http://www.nrel.gov/docs/fy15osti/64072.pdf. EPA’s goal thus did not take into

account the difficulties for Wyoming in developing renewables in the protected sage

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grouse corridor. Wyoming Department of Environmental Quality Comments at 20,

EPA-HQ-OAR-2013-0602-22977, JA__.

To avoid those difficulties, EPA should have formally consulted under the

Endangered Species Act (“ESA”), 16 U.S.C. §§ 1531-1544, to determine whether the

Rule would jeopardize threatened and endangered species. Under the ESA, federal

agencies must ensure “any action authorized, funded, or carried out by such agency”

is not likely to jeopardize the continued existence of any endangered or threatened

species. Id. § 1536(a)(2).

The Rule is no typical CAA rulemaking. EPA designed the Rule to envelop

non-jurisdictional assets, like wind farms, and to fundamentally transform the electric

sector, resulting in significant new solar and wind power generation projects with the

potential to significantly impact threatened and endangered species. 80 Fed. Reg. at

64,926, JA __. Yet EPA refused to consult under the ESA, asserting that the Rule’s

impacts were not “sufficiently certain to occur so as to require consultation.” Id. at

64,925-27, JA __-__. This was error. E.g., Conner v. Burford, 848 F.2d 1441, 1453 (9th

Cir. 1988) (lack of fulsome information not sufficient to justify failure to consult).

EPA’s excuse is also belied by past agency actions. For example, when the

federal government considered the environmental impacts from siting and authorizing

wind farms throughout the Upper Great Plains, the authorizing agency consulted with

the Fish and Wildlife Service on a programmatic level, despite the fact that (i) the

study area spanned all or part of six States, (ii) the exact location of the possible wind

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farms was unknown, and (iii) the proposed action did not authorize planning,

construction, or operation of any specific projects. 80 Fed. Reg. 24,914, 24,915 (May

1, 2015).27 Moreover, the Services’ implementing regulations allow an agency to

consult with the Services in incremental steps, which EPA neglected to consider. 50

C.F.R. § 402.14(k). Such “[i]ncremental step consultation is most appropriate for long-

term, multi-staged activities for which agency actions occur in discrete steps[].”

Endangered Species Consultation Handbook at 5-8 (Mar. 1998). That is precisely the

situation here. 80 Fed. Reg. 64,663-82, JA __-__. EPA’s failure to do so, especially in

light of Wyoming’s specific concerns, was arbitrary and capricious.

D. The Rule Would Cause Particular Harm to Utah.

Utah also will experience unique harms that demonstrate EPA’s arbitrary and

capricious actions here: EPA based Utah’s emission limits on erroneous and

unrepresentative baseline data and the Rule interferes with the State’s ability to protect

its most sensitive air shed.

1. Utah’s Targets Are Unrepresentative Of Historic Utah Emissions.

EPA’s Utah CO2 emission baselines and targets do not represent Utah’s true

baseline emissions because EPA failed to account for a five-month outage at the

State’s largest coal-fired power plant, thus unfairly penalizing Utah. Goal

27 See generally http://plainswindeis.anl.gov/documents

/fpeis/UGP_Wind_BA.pdf (Apr. 2015).

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Computation TSD Appendix, JA__. EPA’s arbitrary approach resulted in the

establishment of unrepresentative baseline emissions and unfairly stringent

performance standards for Utah.

Because EPA used only 2012 emissions to establish the State baselines and

goals, it failed to account for the fact that Unit 1 at the Intermountain Power Project

(“IPP”) plant had a significant outage of five months during 2012. Intermountain

Power Agency Comments at 5, EPA-HQ-OAR-2013-0602-24053, JA __. IPP is

Utah’s largest coal plant and typically represents almost one-third of Utah’s annual

electric generation, making the outage’s impact on EPA’s 2012 baseline and Utah’s

final goal significant. Goal Computation TSD Appendix, JA __. The Intermountain

Power Agency and Utah raised this issue with EPA, IPA Comments at 5, JA__; Utah

Comments at 9, EPA-HQ-OAR-2013-0602-23100, JA__, but EPA was unresponsive

and wrongly assumed that other state power plants had compensated for the outage.

In fact, the vast majority of power produced at IPP is sent to California, and Utah

plants were not deployed to make up the shortfall. IPA Comments at 6, JA __.

EPA set Utah’s 2030 mass-based emissions target at 23,778,193 tons of CO2.

See 80 Fed. Reg. at 64,825, JA__. Adjusting Utah’s baseline upwards to account for

the significant outage at IPP would add potentially two-and-a-half million tons to the

target. See Goal Computation TSD Appendix, JA__. EPA has imposed arbitrarily

more stringent CO2 goals on Utah that will substantially increase compliance costs.

The Rule has set targets for some States that are above their current emissions, see 80

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Fed. Reg. at 64,825, JA__, Statewide Mass-Based CO2 Emission Performance Goals,

JA__, potentially providing them tradeable value that States like Utah that have limits

below their current emissions will need to purchase.

2. The Rule Unlawfully Impedes Utah’s Ability to Protect Its Most Sensitive Air Shed.

In developing Utah’s targets, EPA arbitrarily assumed Utah’s natural gas plants

could increase their usage 40 to 50% to run at 75% of summer capacity, interfering

with Utah’s ability to manage its most sensitive air shed in protection of the health

and welfare of its citizens. See 80 Fed. Reg. at 64,795, JA__. Utah’s coal-fired power

plants are located in sparsely populated areas. See Utah’s Energy Landscape, Utah

Geological Survey, Circular 117 at 40 (2014), http://energy.utah.gov/wp-

content/uploads/Utahs-Energy-Landscape-3rd-Edition.pdf. All of Utah’s major gas

plants are located in Utah’s most urbanized area, the Wasatch Front, where over 70%

of Utah’s citizens live.28 By requiring greater usage of those gas-fired plants, the Rule

would increase the emissions directly affecting over 70% of Utah’s citizens, and

unlawfully interfere with the State’s ability to protect its citizens’ health and welfare.

Indeed, as part of its state implementation plan, Utah has agreed to run its gas

units at lower (moderate) capacities. See e.g. Utah State Implementation Plan, Control

28 Utah Legislature Population Briefing Paper (2014 Session), Office of

Legislative Research and General Counsel, le.utah.gov/lrgc/briefings/ PopulationBriefing2014.pdf.

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Measures for Area and Point Sources, Fine Particulate Matter, PM 2.5 SIP for the

Provo, Utah Nonattainment Area, Section IX, Part A.22.29 This creates numerous

legal and practical conflicts with the Rule. All four of Utah’s existing gas-fired plants

are located in or adjacent to non-attainment areas for PM2.5 that face strict limits on

NOx emissions as a result. Id. Requiring redispatch to higher levels of gas utilization

conflicts with the state plan and other environmental requirements. Moreover, EPA

recently finalized a more stringent ozone standard, 79 Fed. Reg. 65,292 (Oct. 26,

2015), creating additional uncertainty and constraints.

E. EPA Failed To Take Into Account States Like New Jersey That Have Chosen To Deregulate Energy Services.

The Rule fails to consider the positions of the numerous energy-deregulated

States in assuming that state utility regulators can impose the Rule’s requirements on

affected units. See, e.g., RTC Ch. 1 §§ 1.11-1.15 28-29, 33, 135, JA__- __, __, ___. The

Rule will require each energy-deregulated State to pass new legislation specific to its

unique energy market structure, infringing upon the States’ sovereignty. See Core

Issues Brief at Section IV.

For example, New Jersey in 1999 deregulated its energy regulatory structure,

limiting the jurisdiction of the New Jersey Board of Public Utilities (NJBPU) to the

regulation of electric and gas distribution companies. See Electric Discount & Energy

29 http://www.deq.utah.gov/Pollutants/P/pm/pm25/.

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Competition Act, N.J.S.A. 48:3-49 et seq. (the “N.J. Act”). NJBPU no longer exercises

authority over generating units and will therefore require significant legislative and

regulatory changes to comply with the Rule. New Jersey Technical Comments at 8,

JA__. Other States, like Texas, face similar issues. Luminant Comments at 48-49,

JA__-__.

New Jersey would also have to enact new legislation to order the

implementation of energy efficiency measures related to the electric transmission

system to comply with the Rule. As an energy-deregulated state, New Jersey is a

member of PJM Interconnection, LLC, the federally-authorized regional transmission

organization. Id. at 27, JA__. Implementation of the Rule would involve an extensive

reorganization of the power grid and electric distribution within New Jersey and

across the entire PJM region.

Additionally, at a minimum, NJBPU would require amendments to New

Jersey’s existing statutes and regulations governing its renewable portfolio standard.

Those regulations30 require electric suppliers to include minimum renewable energy

amounts in the electricity they sell. N.J. Stat. Ann. 48:3-87(d); N.J. Admin. Code 14:8-

2.3. The rules specify separate minimum requirements for solar electric generation,

Class I renewable energy, and Class II renewable energy. N.J. Admin. Code 14:8-

2.3(a), (k). A renewable energy credit or solar renewable energy credit represents all of

30 Found at N.J.A.C. 14:8-2.1, et seq. and authorized by N.J.S.A. 48:3-49, et seq.

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the environmental benefits or attributes of one megawatt hour of generation from

either a Class I or Class II renewable energy or solar energy facility. N.J. Stat. Ann.

48:3-51. By contrast, the Rule provides for an emission reduction credit for only CO2,

which is but one of the environmental benefits in the New Jersey renewable or solar

energy credit system. Moreover, the Rule does not account for the out-of-state

purchase of RECs. New Jersey’s statutes and regulations would need to be revised

because the same megawatt hour could not satisfy both requirements.

F. EPA Arbitrarily Excluded From Consideration Prior Emissions Reductions Achieved In North Carolina.

EPA failed to recognize the substantial emission reductions achieved in North

Carolina under its 2002 Clean Smokestacks Act (“CSA”). The CSA required stringent

emission reductions on coal units to be achieved within ten years. N.C. Gen. Stat. §

143-215.107D(b)-(e). The CSA allowed regulated operators to determine for the units

in their systems how to achieve the reductions, rather than imposing specific emission

limitations on a unit-by-unit basis. Id. § 143-215.107D(f). Additionally, the North

Carolina utilities decided starting in 2009 to invest in new gas generating units and

close small, inefficient and uncontrolled coal units. N.C. Utilities Comm’n Docket

No. E-2, sub 960, Progress Energy Carolina Application To Construct a 950-MW

Combined Cycle Natural Gas Fueled Electric Generation Facility in Wayne County

(Aug. 18, 2009), JA__.

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EPA arbitrarily ignored these emission reductions when it set North Carolina’s

emission goals. For example, in 2005, the first year in which measures were beginning

to be implemented to comply with the CSA, statewide CO2 emissions from affected

North Carolina units totaled 78,000,000 tons. EPA Clean Air Markets Program Data,

http://ampd.epa.gov/ampd/. Those same sources’ CO2 emissions dropped to just

under 58 million tons in 2012, the Rule’s baseline year, a decrease of nearly 25%. Goal

Computation TSD Appendix, JA__.

The final mass goal set for North Carolina is 51,266,234 tons of CO2 annually.

80 Fed. Reg. at 64,825, JA__. But most of the CO2 emission reductions that can

reasonably be achieved have already been achieved through coal retirements and

natural gas conversion. Implementation of the “Clean Smokestacks Act”: Report to

N.C. Envtl. Review Comm’n (May 30, 2014), http://daq.state.nc.us/news/

leg/2014_Clean_Smokestacks_Act_Report.pdf. Yet, North Carolina received no

credit for this pioneering work.

The aggregate rate goal set for North Carolina is 1,136 lbs CO2/MWh. See 80

Fed. Reg. at 64,824, JA__. In 2012, the baseline year, North Carolina’s aggregate rate

of CO2 emissions per megawatt-hour was 1,778. Goal Computation TSD Appendix,

JA__. In 2005, the aggregate rate was 1,986. Clean Air Markets Program Data: EIA,

form EIA-923 and detailed data, www.eia.gov/electricity/data/eia923. EPA gave no

credit to that 11% rate decrease, despite the fact that, in 2012, the North Carolina rate

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for coal units was the lowest in the country and its rate for gas facilities the eighth

lowest.

North Carolina is being penalized for its exemplary record of clean energy

generation well in advance of EPA’s efforts a decade later.

CONCLUSION

For the foregoing reasons, as well as those set forth in the Core Issues Brief,

the petitions should be granted and the Rule vacated.

Dated: February 19, 2016 Respectfully submitted,

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/s/ Thomas A. Lorenzen

Thomas A. Lorenzen Sherrie A. Armstrong CROWELL & MORING LLP 1001 Pennsylvania Ave., N.W. Washington, D.C. 20004 Tel: (202) 624-2500 tlorenzen@crowell.com sarmstrong@crowell.com Counsel for Petitioners National Rural Electric Cooperative Association; Big Rivers Electric Corporation; Brazos Electric Power Cooperative, Inc.; Buckeye Power, Inc.; Central Montana Electric Power Cooperative; Central Power Electric Cooperative, Inc., Corn Belt Power Cooperative; Dairyland Power Cooperative; East River Electric Power Cooperative, Inc.; Georgia Transmission Corporation; Kansas Electric Power Cooperative, Inc.; North Carolina Electric Membership Corporation; Northwest Iowa Power Cooperative; Oglethorpe Power Corporation; PowerSouth Energy Cooperative; Prairie Power, Inc.; Rushmore Electric Power Cooperative, Inc.; Seminole Electric Cooperative, Inc.; Southern Illinois Power Cooperative; Sunflower Electric Power Corporation; and Upper Missouri G. & T. Electric Cooperative, Inc.

/s/ Elbert Lin Patrick Morrisey ATTORNEY GENERAL OF WEST VIRGINIA Elbert Lin Solicitor General Counsel of Record J. Zak Ritchie Assistant Attorney General State Capitol Building 1, Room 26-E Charleston, WV 25305 Tel: (304) 558-2021 Fax: (304) 558-0140 elbert.lin@wvago.gov Counsel for Petitioner State of West Virginia

Of Counsel Rae Cronmiller Environmental Counsel NATIONAL ASSOCIATION OF RURAL

ELECTRIC COOPERATIVES 4301 Wilson Blvd. Arlington, VA 22203 Tel: (703) 907-5500 rae.cronmiller@nreca.coop

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/s/ Scott A. Keller Ken Paxton ATTORNEY GENERAL OF TEXAS Charles E. Roy First Assistant Attorney General Scott A. Keller Solicitor General Counsel of Record P.O. Box 12548 Austin, TX 78711-2548 Tel: (512) 936-1700 scott.keller@texasattorneygeneral.gov Counsel for Petitioner State of Texas

/s/ Andrew Brasher Luther Strange ATTORNEY GENERAL OF ALABAMA Andrew Brasher Solicitor General Counsel of Record 501 Washington Avenue Montgomery, AL 36130 Tel: (334) 590-1029 abrasher@ago.state.al.us Counsel for Petitioner State of Alabama

/s/ John R. Lopez IV Mark Brnovich ATTORNEY GENERAL OF ARIZONA John R. Lopez IV Counsel of Record Dominic E. Draye Keith Miller Assistant Attorneys General Maureen Scott Janet Wagner Janice Alward Arizona Corp. Commission, Staff Attorneys 1275 West Washington

Phoenix, AZ 85007

Tel: (602) 542-5025 john.lopez@azag.gov dominic.draye@azag.gov keith.miller@azag.gov Counsel for Petitioner Arizona Corporation Commission

/s/ Jamie L. Ewing Leslie Rutledge ATTORNEY GENERAL OF ARKANSAS Lee Rudofsky Solicitor General Jamie L. Ewing Assistant Attorney General Counsel of Record 323 Center Street, Suite 400 Little Rock, AR 72201 Tel: (501) 682-5310 jamie.ewing@arkansasag.gov Counsel for Petitioner State of Arkansas

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/s/ Frederick Yarger Cynthia H. Coffman ATTORNEY GENERAL OF COLORADO Frederick Yarger Solicitor General Counsel of Record 1300 Broadway, 10th Floor Denver, CO 80203 Tel: (720) 508-6168 fred.yarger@state.co.us Counsel for Petitioner State of Colorado

/s/ Allen Winsor Pamela Jo Bondi ATTORNEY GENERAL OF FLORIDA Allen Winsor Solicitor General of Florida Counsel of Record Office of the Attorney General PL-01, The Capitol Tallahassee, FL 32399-1050 Tel: (850) 414-3681 Fax: (850) 410-2672 allen.winsor@myfloridalegal.com Counsel for Petitioner State of Florida

/s/ Britt C. Grant Samuel S. Olens ATTORNEY GENERAL OF GEORGIA Britt C. Grant Solicitor General Counsel of Record 40 Capitol Square S.W. Atlanta, GA 30334 Tel: (404) 656-3300 Fax: (404) 463-9453 bgrant@law.ga.gov Counsel for Petitioner State of Georgia

/s/ Timothy Junk Gregory F. Zoeller ATTORNEY GENERAL OF INDIANA Timothy Junk Deputy Attorney General Counsel of Record Indiana Government Ctr. South Fifth Floor 302 West Washington Street Indianapolis, IN 46205 Tel: (317) 232-6247

tim.junk@atg.in.gov Counsel for Petitioner State of Indiana

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/s/ Jeffrey A. Chanay Derek Schmidt ATTORNEY GENERAL OF KANSAS Jeffrey A. Chanay Chief Deputy Attorney General Counsel of Record Bryan C. Clark Assistant Solicitor General 120 S.W. 10th Avenue, 3rd Floor Topeka, KS 66612 Tel: (785) 368-8435 Fax: (785) 291-3767 jeff.chanay@ag.ks.gov Counsel for Petitioner State of Kansas

/s/ Gregory T. Dutton_________ Andy Beshear ATTORNEY GENERAL OF KENTUCKY Gregory T. Dutton Assistant Attorney General Counsel of Record

700 Capital Avenue

Suite 118 Frankfort, KY 40601 Tel: (502) 696-5453 gregory.dutton@ky.gov Counsel for Petitioner Commonwealth of Kentucky

/s/ Steven B. “Beaux” Jones

Jeff Landry ATTORNEY GENERAL OF LOUISIANA Steven B. “Beaux” Jones Counsel of Record Duncan S. Kemp, IV Assistant Attorneys General Environmental Section – Civil Division 1885 N. Third Street Baton Rouge, LA 70804 Tel: (225) 326-6085 Fax: (225) 326-6099 jonesst@ag.state.la.us Counsel for Petitioner State of Louisiana

/s/ Donald Trahan Herman Robinson Executive Counsel Donald Trahan Counsel of Record Elliott Vega LOUISIANA DEPARTMENT OF

ENVIRONMENTAL QUALITY Legal Division P.O. Box 4302 Baton Rouge, LA 70821-4302 Tel: (225) 219-3985 Fax: (225) 219-4068 donald.trahan@la.gov Counsel for Petitioner State of Louisiana Department of Environmental Quality

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/s/ Monica Derbes Gibson____ Monica Derbes Gibson Lesley Foxhall Pietras LISKOW & LEWIS, P.L.C. 701 Poydras Street, Suite 5000 New Orleans, LA 70139 Tel: (504) 556-4010 Fax: (504) 556-4108 mdgibson@liskow.com lfpietras@liskow.com Counsel for Petitioner Louisiana Public Service Commission

/s/ Aaron D. Lindstrom Bill Schuette ATTORNEY GENERAL FOR THE PEOPLE OF MICHIGAN Aaron D. Lindstrom Michigan Solicitor General Counsel of Record P.O. Box 30212 Lansing, MI 48909 Tel: (515) 373-1124 Fax: (517) 373-3042 lindstroma@michigan.gov Counsel for Petitioner People of the State of Michigan

/s/ Harold E. Pizzetta, III_____ Jim Hood ATTORNEY GENERAL OF THE STATE OF MISSISSIPPI Harold E. Pizzetta Assistant Attorney General Civil Litigation Division Office of the Attorney General Post Office Box 220 Jackson, MS 39205 Tel: (601) 359-3816 Fax: (601) 359-2003 hpizz@ago.state.ms.us Counsel for Petitioner State of Mississippi

/s/ Donna J. Hodges Donna J. Hodges Senior Counsel MISSISSIPPI DEPARTMENT OF

ENVIRONMENTAL QUALITY P.O. Box 2261 Jackson, MS 39225-2261 Tel: (601) 961-5369 Fax: (601) 961-5349 donna_hodges@deq.state.ms.us Counsel for Petitioner Mississippi Department of Environmental Quality

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/s/ Todd E. Palmer Todd E. Palmer Valerie L. Green MICHAEL, BEST & FRIEDRICH LLP 601 Pennsylvania Ave., N.W., Suite 700 Washington, D.C. 20004-2601 Tel: (202) 747-9560 Fax: (202) 347-1819 tepalmer@michaelbest.com vlgreen@michaelbest.com Counsel for Petitioner Mississippi Public Service Commission

/s/ James R. Layton Chris Koster ATTORNEY GENERAL OF MISSOURI James R. Layton Solicitor General Counsel of Record P.O. Box 899 207 W. High Street Jefferson City, MO 65102 Tel: (573) 751-1800 Fax: (573) 751-0774 james.layton@ago.mo.gov Counsel for Petitioner State of Missouri

/s/ Dale Schowengerdt Timothy C. Fox ATTORNEY GENERAL OF MONTANA Alan Joscelyn Chief Deputy Attorney General Dale Schowengerdt Solicitor General Counsel of Record 215 North Sanders Helena, MT 59620-1401 Tel: (406) 444-7008 dales@mt.gov Counsel for Petitioner State of Montana

/s/ Justin D. Lavene Doug Peterson ATTORNEY GENERAL OF NEBRASKA Dave Bydlaek Chief Deputy Attorney General Justin D. Lavene Assistant Attorney General Counsel of Record 2115 State Capitol Lincoln, NE 68509 Tel: (402) 471-2834 justin.lavene@nebraska.gov Counsel for Petitioner State of Nebraska

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/s/ Robert J. Kinney John J. Hoffman ACTING ATTORNEY GENERAL OF NEW JERSEY David C. Apy Assistant Attorney General Robert J. Kinney Deputy Attorney General Counsel of Record Division of Law R.J. Hughes Justice Complex P.O. Box 093 25 Market Street Trenton, NJ 08625-0093 Tel: (609) 292-6945 Fax: (609) 341-5030 robert.kinney@dol.lps.state.nj.us Counsel for Petitioner State of New Jersey

/s/ Paul M. Seby Wayne Stenehjem ATTORNEY GENERAL OF NORTH DAKOTA Margaret Olson Assistant Attorney General North Dakota Attorney General’s Office 600 E. Boulevard Avenue #125 Bismarck, ND 58505 Tel: (701) 328-3640 maiolson@nd.gov Paul M. Seby Special Assistant Attorney General State of North Dakota GREENBERG TRAURIG, LLP 1200 17th Street, Suite 2400 Denver, CO 80202 Tel: (303) 572-6500 Fax: (303) 572-6540 sebyp@gtlaw.com Counsel for Petitioner State of North Dakota

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/s/ Eric E. Murphy Michael DeWine ATTORNEY GENERAL OF OHIO Eric E. Murphy State Solicitor Counsel of Record 30 E. Broad Street, 17th Floor Columbus, OH 43215 Tel: (614) 466-8980 eric.murphy@ohioattorneygeneral.gov Counsel for Petitioner State of Ohio

/s/ David B. Rivkin, Jr. E. Scott Pruitt ATTORNEY GENERAL OF OKLAHOMA Patrick R. Wyrick Solicitor General of Oklahoma 313 N.E. 21st Street Oklahoma City, OK 73105 Tel: (405) 521-4396 Fax: (405) 522-0669 fc.docket@oag.state.ok.us scott.pruitt@oag.ok.gov David B. Rivkin, Jr. Counsel of Record Mark W. DeLaquil Andrew M. Grossman BAKER & HOSTETLER LLP Washington Square, Suite 1100 1050 Connecticut Ave., N.W. Washington, D.C. 20036 Tel: (202) 861-1731 Fax: (202) 861-1783 drivkin@bakerlaw.com Counsel for Petitioners State of Oklahoma and Oklahoma Department of Environmental Quality

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/s/ James Emory Smith, Jr. Alan Wilson ATTORNEY GENERAL OF SOUTH CAROLINA Robert D. Cook Solicitor General James Emory Smith, Jr. Deputy Solicitor General Counsel of Record P.O. Box 11549 Columbia, SC 29211 Tel: (803) 734-3680 Fax: (803) 734-3677 esmith@scag.gov Counsel for Petitioner State of South Carolina

/s/ Steven R. Blair Marty J. Jackley ATTORNEY GENERAL OF SOUTH DAKOTA Steven R. Blair Assistant Attorney General Counsel of Record 1302 E. Highway 14, Suite 1 Pierre, SD 57501 Tel: (605) 773-3215 steven.blair@state.sd.us Counsel for Petitioner State of South Dakota

/s/ Tyler R. Green Sean Reyes ATTORNEY GENERAL OF UTAH Tyler R. Green Solicitor General Counsel of Record Parker Douglas Federal Solicitor Utah State Capitol Complex 350 North State Street, Suite 230 Salt Lake City, UT 84114-2320 pdouglas@utah.gov Counsel for Petitioner State of Utah

/s/ Misha Tseytlin ______ Brad Schimel ATTORNEY GENERAL OF WISCONSIN Misha Tseytlin Solicitor General Counsel of Record Andrew Cook Deputy Attorney General Delanie M. Breuer Assistant Deputy Attorney General Wisconsin Department of Justice 17 West Main Street Madison, WI 53707 Tel: (608) 267-9323 tseytlinm@doj.state.wi.us Counsel for Petitioner State of Wisconsin

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/s/ James Kaste Peter K. Michael ATTORNEY GENERAL OF WYOMING James Kaste Deputy Attorney General Counsel of Record Michael J. McGrady Erik Petersen Senior Assistant Attorneys General Elizabeth Morrisseau Assistant Attorney General 2320 Capitol Avenue Cheyenne, WY 82002 Tel: (307) 777-6946 Fax: (307) 777-3542 james.kaste@wyo.gov Counsel for Petitioner State of Wyoming

/s/ Sam M. Hayes Sam M. Hayes General Counsel Counsel of Record Craig Bromby Deputy General Counsel Andrew Norton Deputy General Counsel NORTH CAROLINA DEPARTMENT OF

ENVIRONMENTAL QUALITY 1601 Mail Service Center Raleigh, NC 27699-1601 Tel: (919) 707-8616 sam.hayes@ncdenr.gov Counsel for Petitioner North Carolina Department of Environmental Quality

/s/ Dennis Lane____ Dennis Lane STINSON LEONARD STREET LLP 1775 Pennsylvania Ave., N.W., Suite 800 Washington, D.C. 20006 Tel: (202) 785-9100 Fax: (202) 785-9163 dennis.lane@stinson.com Parthenia B. Evans STINSON LEONARD STREET LLP 1201 Walnut Street, Suite 2900 Kansas City, MO 64106 Tel: (816) 842-8600 Fax: (816) 691-3495 parthy.evans@stinson.com Counsel for Petitioner Kansas City Board of Public Utilities – Unified Government of Wyandotte County/Kansas City, Kansas

/s/ Allison D. Wood F. William Brownell Allison D. Wood Henry V. Nickel Tauna M. Szymanski HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 bbrownell@hunton.com awood@hunton.com hnickel@hunton.com tszymanski@hunton.com Counsel for Petitioners Utility Air Regulatory Group and American Public Power Association

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/s/ Stacey Turner ______ Stacey Turner SOUTHERN COMPANY SERVICES, INC. 600 18th Street North BIN 14N-8195 Birmingham, AL 35203 Tel: (205) 257-2823 staturne@southernco.com Counsel for Petitioners Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company /s/ Margaret Claiborne Campbell Margaret Claiborne Campbell Angela J. Levin TROUTMAN SANDERS LLP 600 Peachtree Street, NE, Suite 5200 Atlanta, GA 30308-2216 Tel: (404) 885-3000 margaret.campbell@troutmansanders.com angela.levin@troutmansanders.com Counsel for Petitioner Georgia Power Company

/s/ C. Grady Moore, III C. Grady Moore, III Steven G. McKinney BALCH & BINGHAM LLP 1901 Sixth Avenue North, Suite 1500 Birmingham, AL 35303-4642 Tel: (205) 251-8100 Fax: (205) 488-5704 gmoore@balch.com smckinney@balch.com Counsel for Petitioner Alabama Power Company /s/ Terese T. Wyly Terese T. Wyly Ben H. Stone BALCH & BINGHAM LLP 1310 Twenty Fifth Avenue Gulfport, MS 39501-1931 Tel: (228) 214-0413 twyly@balch.com bstone@balch.com Counsel for Petitioner Mississippi Power Company

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/s/ Jeffrey A. Stone Jeffrey A. Stone BEGGS & LANE, RLLP 501 Commendencia Street Pensacola, FL 32502 Tel: (850) 432-2451 JAS@beggslane.com James S. Alves 2110 Trescott Drive Tallahassee, FL 32308 Tel: (850) 566-7607 jim.s.alves@outlook.com Counsel for Petitioner Gulf Power Company

/s/ Christina F. Gomez Christina F. Gomez Lawrence E. Volmert Garrison W. Kaufman Jill H. Van Noord HOLLAND & HART LLP 555 Seventeenth Street, Suite 3200 Denver, CO 80202 Tel: (303) 295-8000 Fax: (303) 295-8261 cgomez@hollandhart.com lvolmert@hollandhart.com gwkaufman@hollandhart.com jhvannoord@hollandhart.com Patrick R. Day HOLLAND & HART LLP 2515 Warren Avenue, Suite 450 Cheyenne, WY 82001 Tel: (307) 778-4200 Fax: (307) 778-8175 pday@hollandhart.com Emily C. Schilling HOLLAND & HART LLP 222 South Main Street, Suite 2200 Salt Lake City, UT 84101 Tel: (801) 799-5800 Fax: (801) 799-5700 ecschilling@hollandhart.com Counsel for Petitioner Basin Electric Power Cooperative

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/s/ James S. Alves ______ James S. Alves 2110 Trescott Drive Tallahassee, FL 32308 Tel: (850) 566-7607 jim.s.alves@outlook.com Counsel for Petitioner CO2 Task Force of the Florida Electric Power Coordinating Group, Inc.

/s/ John J. McMackin______ John J. McMackin WILLIAMS & JENSEN 701 8th Street, N.W., Suite 500 Washington, D.C. 20001 Tel: (202) 659-8201 jjmcmackin@wms-jen.com Counsel for Petitioner Energy-Intensive Manufacturers Working Group on Greenhouse Gas Regulation

/s/ William M. Bumpers William M. Bumpers Megan H. Berge BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004 Tel: (202) 639-7700 william.bumpers@bakerbotts.com megan.berge@bakerbotts.com Kelly McQueen ENTERGY SERVICES, INC. 425 W. Capitol Avenue, 27th Floor Little Rock, AR 72201 Tel: (501) 377-5760 kmcque1@entergy.com Counsel for Petitioner Entergy Corporation

/s/ Paul J. Zidlicky____ Paul J. Zidlicky SIDLEY AUSTIN, LLP 1501 K Street, N.W. Washington, D.C. 20005 Tel: (202) 736-8000 pzidlicky@sidley.com Counsel for Petitioners GenOn Mid-Atlantic, LLC; Indian River Power LLC; Louisiana Generating LLC; Midwest Generation, LLC; NRG Chalk Point LLC; NRG Power Midwest LP; NRG Rema LLC; NRG Texas Power LLC; NRG Wholesale Generation LP; and Vienna Power LLC

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/s/ David M. Flannery____ David M. Flannery Kathy G. Beckett Edward L. Kropp STEPTOE & JOHNSON, PLLC 505 Virginia Street East Charleston, WV 25326 Tel: (304) 353-8000 dave.flannery@steptoe-johnson.com kathy.beckett@steptoe-johnson.com skipp.kropp@steptoe-johnson.com Stephen L. Miller STEPTOE & JOHNSON, PLLC 700 N. Hurstbourne Parkway, Suite 115 Louisville, KY 40222 Tel: (502) 423-2000 steve.miller@steptoe-johnson.com Counsel for Petitioner Indiana Utility Group

/s/ F. William Brownell F. William Brownell Eric J. Murdock HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 bbrownell@hunton.com emurdock@hunton.com Nash E. Long III HUNTON & WILLIAMS LLP Bank of America Plaza, Suite 3500 101 South Tryon Street Charlotte, NC 28280 Tel: (704) 378-4700 nlong@hunton.com Counsel for Petitioner LG&E and KU Energy LLC

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/s/ P. Stephen Gidiere III P. Stephen Gidiere III Thomas L. Casey III Julia B. Barber BALCH & BINGHAM LLP 1901 6th Ave. N., Suite 1500 Birmingham, AL 35203 Tel: (205) 251-8100 sgidiere@balch.com Stephanie Z. Moore Vice President and General Counsel Luminant Generation Company LLC 1601 Bryan Street, 22nd Floor Dallas, TX 75201 Daniel J. Kelly Vice President and Associate General Counsel Energy Future Holdings Corp. 1601 Bryan Street, 43rd Floor Dallas, TX 75201 Counsel for Petitioners Luminant Generation Company LLC; Oak Grove Management Company LLC; Big Brown Power Company LLC; Sandow Power Company LLC; Big Brown Lignite Company LLC; Luminant Mining Company LLC; and Luminant Big Brown Mining Company LLC

/s/ Ronald J. Tenpas Ronald J. Tenpas MORGAN, LEWIS & BOCKIUS 1111 Pennsylvania Avenue, N.W. Washington, D.C. 20004 Tel: (202) 739-3000 rtenpas@morganlewis.com Counsel for Petitioner Minnesota Power (an operating division of ALLETE, Inc.)

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/s/ Allison D. Wood Allison D. Wood Tauna M. Szymanski Andrew D. Knudsen HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 awood@hunton.com tszymanski@hunton.com aknudsen@hunton.com Counsel for Petitioner Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc.

/s/ Joshua R. More____ Joshua R. More Jane E. Montgomery Amy Antoniolli Raghav Murali SCHIFF HARDIN LLP 233 South Wacker Drive Suite 6600 Chicago, IL 60606 Tel: (312) 258-5500 jmore@schiffhardin.com jmontgomery@schiffhardin.com aantoniolli@schiffhardin.com rmurali@schiffhardin.com Counsel for Petitioner Prairie State Generating Company, LLC

/s/ Eric L. Hiser Eric L. Hiser JORDEN BISCHOFF & HISER, PLC 7272 E. Indian School Road, Suite 360 Scottsdale, AZ 85251 Tel: (480) 505-3927 ehiser@jordenbischoff.com Counsel for Petitioner Arizona Electric Power Cooperative, Inc.

/s/ Brian A. Prestwood Brian A. Prestwood Senior Corporate and Compliance Counsel ASSOCIATED ELECTRIC COOPERATIVE, INC. 2814 S. Golden, P.O. Box 754 Springfield, MO 65801 Tel: (417) 885-9273 bprestwood@aeci.org Counsel for Petitioner Associated Electric Cooperative, Inc.

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/s/ Christopher L. Bell Christopher L. Bell GREENBERG TRAURIG LLP 1000 Louisiana Street, Suite 1700 Houston, TX 77002 Tel: (713) 374-3556 bellc@gtlaw.com Counsel for Petitioner Golden Spread Electrical Cooperative, Inc.

/s/ David Crabtree David Crabtree Vice President, General Counsel DESERET GENERATION & TRANSMISSION

CO-OPERATIVE 10714 South Jordan Gateway South Jordan, UT 84095 Tel: (801) 619-9500 Crabtree@deseretpower.com Counsel for Petitioner Deseret Generation & Transmission Co-operative

/s/ John M. Holloway III John M. Holloway III, DC Bar # 494459 SUTHERLAND ASBILL & BRENNAN LLP 700 Sixth Street, N.W., Suite 700 Washington, D.C. 20001 Tel: (202) 383-0100 Fax: (202) 383-3593 jay.holloway@sutherland.com Counsel for Petitioners East Kentucky Power Cooperative, Inc.; Hoosier Energy Rural Electric Cooperative, Inc.; Minnkota Power Cooperative, Inc.; and South Mississippi Electric Power Association

/s/ Patrick Burchette Patrick Burchette HOLLAND & KNIGHT LLP 800 17th Street, N.W., Suite 1100 Washington, D.C. 20006 Tel: (202) 469-5102 Patrick.Burchette@hklaw.com Counsel for Petitioners East Texas Electric Cooperative, Inc.; Northeast Texas Electric Cooperative, Inc.; Sam Rayburn G&T Electric Cooperative, Inc.; and Tex-La Electric Cooperative of Texas, Inc.

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/s/ Mark Walters Mark Walters D.C. Cir. Bar No. 54161 Michael J. Nasi D.C. Cir. Bar No. 53850 JACKSON WALKER L.L.P. 100 Congress Avenue, Suite 1100 Austin, TX 78701 Tel: (512) 236-2000 mwalters@jw.com mnasi@jw.com Counsel for Petitioners San Miguel Electric Cooperative, Inc. and South Texas Electric Cooperative, Inc.

/s/ Randolph G. Holt Randolph G. Holt Jeremy L. Fetty PARR RICHEY OBREMSKEY FRANDSEN &

PATTERSON LLP Wabash Valley Power Association, Inc. 722 N. High School Road P.O. Box 24700 Indianapolis, IN 46224 Tel: (317) 481-2815 R_holt@wvpa.com jfetty@parrlaw.com Counsel for Petitioner Wabash Valley Power Association, Inc.

/s/ Megan H. Berge Megan H. Berge BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004 Tel: (202) 639-7700 megan.berge@bakerbotts.com Counsel for Petitioner Western Farmers Electric Cooperative

/s/ Steven C. Kohl Steven C. Kohl Gaetan Gerville-Reache WARNER NORCROSS & JUDD LLP 2000 Town Center, Suite 2700 Southfield, MI 48075-1318 Tel: (248) 784-5000 skohl@wnj.com Counsel for Petitioner Wolverine Power Supply Cooperative, Inc.

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/s/ William M. Bumpers William M. Bumpers Megan H. Berge BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004

Tel: (202) 639-7700

william.bumpers@bakerbotts.com megan.berge@bakerbotts.com Counsel for Petitioner NorthWestern Corporation d/b/a NorthWestern Energy

/s/ Allison D. Wood Allison D. Wood Tauna M. Szymanski Andrew D. Knudsen HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 awood@hunton.com tszymanski@hunton.com aknudsen@hunton.com Counsel for Petitioner Tri-State Generation and Transmission Association, Inc.

/s/ William M. Bumpers William M. Bumpers Megan H. Berge BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004

Tel: (202) 639-7700

william.bumpers@bakerbotts.com megan.berge@bakerbotts.com Counsel for Petitioner Westar Energy, Inc.

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/s/ Jeffrey R. Holmstead Jeffrey R. Holmstead Sandra Y. Snyder BRACEWELL & GIULIANI LLP 2000 K Street, N.W., Suite 500 Washington, D.C. 20006-1872 Tel: (202) 828-5852 Fax: (202) 857-4812 jeff.holmstead@bgllp.com Counsel for Petitioner American Coalition for Clean Coal Electricity

/s/ Geoffrey K. Barnes Geoffrey K. Barnes J. Van Carson Wendlene M. Lavey John D. Lazzaretti Robert D. Cheren SQUIRE PATTON BOGGS (US) LLP 4900 Key Tower 127 Public Square Cleveland, OH 44114 Tel: (216) 479-8646 geoffrey.barnes@squirepb.com Counsel for Petitioner Murray Energy Corporation

/s/ Andrew C. Emrich Andrew C. Emrich HOLLAND & HART LLP 6380 South Fiddlers Green Circle Suite 500 Greenwood Village, CO 80111 Tel: (303) 290-1621

Fax: (866) 711-8046

acemrich@hollandhart.com Emily C. Schilling HOLLAND & HART LLP 222 South Main Street, Suite 2200 Salt Lake City, UT 84101 Tel: (801) 799-5753 Fax: (202) 747-6574 ecschilling@hollandhart.com Counsel for Petitioners Newmont Nevada Energy Investment, LLC and Newmont USA Limited

/s/ Charles T. Wehland____ Charles T. Wehland Counsel of Record Brian J. Murray JONES DAY 77 West Wacker Drive, Suite 3500 Chicago, IL 60601-1692 Tel: (312) 782-3939 Fax: (312) 782-8585 ctwehland@jonesday.com bjmurray@jonesday.com Counsel for Petitioners The North American Coal Corporation; The Coteau Properties Company; Coyote Creek Mining Company, LLC; The Falkirk Mining Company; Mississippi Lignite Mining Company; North American Coal Royalty Company; NODAK Energy Services, LLC; Otter Creek Mining Company, LLC; and The Sabine Mining Company

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/s/ Robert G. McLusky Robert G. McLusky JACKSON KELLY, PLLC 1600 Laidley Tower P.O. Box 553 Charleston, WV 25322 Tel: (304) 340-1000 rmclusky@jacksonkelly.com Counsel for Petitioner West Virginia Coal Association

/s/ Eugene M. Trisko Eugene M. Trisko LAW OFFICES OF EUGENE M. TRISKO P.O. Box 596 Berkeley Springs, WV 25411 Tel: (304) 258-1977 Tel: (301) 639-5238 (cell) emtrisko7@gmail.com Counsel for Petitioner International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers & Helpers

/s/ Eugene M. Trisko Eugene M. Trisko LAW OFFICES OF EUGENE M. TRISKO P.O. Box 596 Berkeley Springs, WV 25411 Tel: (304) 258-1977 Tel: (301) 639-5238 (cell) emtrisko7@gmail.com Counsel for Petitioner International Brotherhood of Electrical Workers, AFL-CIO

/s/ Grant F. Crandall Grant F. Crandall General Counsel UNITED MINE WORKERS OF AMERICA 18354 Quantico Gateway Drive

Triangle, VA 22172

Tel: (703) 291-2429 gcrandall@umwa.org Arthur Traynor, III Staff Counsel UNITED MINE WORKERS OF AMERICA 18354 Quantico Gateway Drive Triangle, VA 22172 Tel: (703) 291-2457 atraynor@umwa.org Eugene M. Trisko LAW OFFICES OF EUGENE M. TRISKO P.O. Box 596 Berkeley Springs, WV 25411 Tel: (304) 258-1977 emtrisko7@gmail.com Counsel for Petitioner United Mine Workers of America

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/s/ Megan H. Berge Megan H. Berge William M. Bumpers BAKER BOTTS L.L.P. 1299 Pennsylvania Avenue, N.W. Washington, D.C. 20004

Tel: (202) 639-7700

megan.berge@bakerbotts.com william.bumpers@bakerbotts.com Counsel for Petitioner National Association of Home Builders

/s/ Kathryn D. Kirmayer Kathryn D. Kirmayer General Counsel Evelyn R. Nackman Associate General Counsel ASSOCIATION OF AMERICAN RAILROADS 425 3rd Street, S.W. Washington, D.C. 20024 Tel: (202) 639-2100 kkirmayer@aar.org Counsel for Petitioner Association of American Railroads

/s/ Scott M. DuBoff Scott M. DuBoff

Matthew R. Schneider

GARVEY SCHUBERT BARER 1000 Potomac Street, N.W., Suite 200 Washington, D.C. 20007 Tel: (202) 965-7880 sduboff@gsblaw.com Counsel for Petitioner Local Government Coalition for Renewable Energy

/s/ Catherine E. Stetson Catherine E. Stetson Eugene A. Sokoloff HOGAN LOVELLS US LLP 555 Thirteenth Street, N.W. Washington, D.C. 20004-1109 Tel: (202) 637-5600 Fax: (202) 637-5910 cate.stetson@hoganlovells.com eugene.sokoloff@hoganlovells.com Counsel for Petitioner Denbury Onshore, LLC

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/s/ Adam R.F. Gustafson______ C. Boyden Gray Adam R.F. Gustafson Counsel of Record Derek S. Lyons James R. Conde BOYDEN GRAY & ASSOCIATES, PLLC 1627 I Street, N.W., #950

Washington, D.C. 20006

Tel: (202) 955-0620 gustafson@boydengrayassociates.com Sam Kazman Hans Bader COMPETITIVE ENTERPRISE INSTITUTE 1899 L Street, N.W., 12th Floor Washington, D.C. 20036 Tel: (202) 331-1010 Counsel for Petitioners Competitive Enterprise Institute; Buckeye Institute for Public Policy Solutions; Independence Institute; Rio Grande Foundation; Sutherland Institute; Klaus J. Christoph; Samuel R. Damewood; Catherine C. Dellin; Joseph W. Luquire; Lisa R. Markham; Patrick T. Peterson; and Kristi Rosenquist Robert Alt BUCKEYE INSTITUTE FOR PUBLIC POLICY

SOLUTIONS 88 E. Broad Street, Suite 1120 Columbus, OH 43215 Tel: (614) 224-4422 robert@buckeyeinstitute.org Counsel for Petitioner Buckeye Institute for Public Policy Solutions

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CERTIFICATE OF COMPLIANCE

Pursuant to Rule 32(a)(7)(C) of the Federal Rules of Appellate Procedure and

Circuit Rules 32(a)(1) and 32(a)(2)(C), I hereby certify that the foregoing Opening

Brief of Petitioners on Procedural and Record-Based Issues contains 19,723 words, as

counted by a word processing system that includes headings, footnotes, quotations,

and citations in the count, and therefore is within the word limit set by the Court.

Dated: February 19, 2016 /s/ Thomas A. Lorenzen Thomas A. Lorenzen

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CERTIFICATE OF SERVICE

I hereby certify that, on this 19th day of February 2016, a copy of the foregoing

Opening Brief of Petitioners on Procedural and Record-Based Issues was served

electronically through the Court’s CM/ECF system on all ECF-registered counsel.

/s/ Thomas A. Lorenzen

Thomas A. Lorenzen

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